|UNITED STATES                     
|----------------------------------
|SECURITIES AND EXCHANGE COMMISSION
|WASHINGTON, D.C. 20549            





|FORM 10‐K
|---------



|ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
|---------------------------------------------
|OF THE SECURITIES EXCHANGE ACT OF 1934       





|For the Fiscal Year EndedDecember 31, 2006
|------------------------------------------





|            |                                    |                   
|----------- | ---------------------------------- | ------------------
|            |                                    |                   
|Commission  | Registrant; State of Incorporation | IRS Employer      
|File Number | Address; and Telephone Number      | Identification No.
|            |                                    |                   
|            |                                    |                   
|001‐01245   | WISCONSIN ELECTRIC POWER COMPANY   | 39‐0476280        
|            | (A Wisconsin Corporation)          |                   
|            | 231 West Michigan Street           |                   
|            | P.O. Box 2046                      |                   
|            | Milwaukee, WI 53201                |                   
|            | (414) 221‐2345                     |                   
|            |                                    |                   





|Securities Registered Pursuant to Section 12(b) of the Act:    None
|-------------------------------------------------------------------
|                                                                   
|Securities Registered Pursuant to Section 12(g) of the Act:        
|Serial Preferred Stock, 3.60% Series, $100 Par Value               
|Six Per Cent.  Preferred Stock, $100 Par Value                     



Indicate by check mark if the registrant is a well‐known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes [  ]    No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes [  ]    No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [X]    No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‐K (Section 229.405 of this Chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10‐K or any amendment to this Form 10‐K.    [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non‐accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b‐2 of the Exchange Act.  (Check one): Large accelerated filer [  ]    Accelerated filer [  ]    Non‐accelerated filer [X].

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‐2 of the Exchange Act).    Yes [  ]    No [X]

---

The aggregate market value of the common equity of Wisconsin Electric Power Company held by non‐affiliates as of June 30, 2006 was zero.  All of the common stock of Wisconsin Electric Power Company is held by Wisconsin Energy Corporation.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2007):



|Common Stock, $10 Par Value, 33,289,327 shares outstanding
|----------------------------------------------------------





|
|

Documents Incorporated by Reference

Portions of Wisconsin Electric Power Company's definitive information statement on Schedule 14C for its Annual Meeting of Stockholders, to be held on April 30, 2007, are incorporated by reference into Part III hereof.

---





|WISCONSIN ELECTRIC POWER COMPANY                     
|-----------------------------------------------------
|                                                     
|FORM 10‐K REPORT FOR THE YEAR ENDED DECEMBER 31, 2006
|                                                     



|TABLE OF CONTENTS                                                                                                        
|-------------------------------------------------------------------------------------------------------------------------
|Item                                                                                                                     
|                                                                                                                         
|PART I                                                                                                                   
|                                                                                                                         
|1.   Business                                                                                                            
|                                                                                                                         
|1A. Risk Factors                                                                                                         
|                                                                                                                         
|1B. Unresolved Staff Comments                                                                                            
|                                                                                                                         
|2.    Properties                                                                                                         
|                                                                                                                         
|3.    Legal Proceedings                                                                                                  
|                                                                                                                         
|4.    Submission of Matters to a Vote of Security Holders                                                                
|                                                                                                                         
|Executive Officers of the Registrant                                                                                     
|                                                                                                                         
|PART II                                                                                                                  
|                                                                                                                         
|5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
       Equity Securities
|                                                                                                                         
|6.    Selected Financial Data                                                                                            
|                                                                                                                         
|7.    Management's Discussion and Analysis of Financial Condition and Results of Operations                              
|                                                                                                                         
|7A. Quantitative and Qualitative Disclosures About Market Risk                                                           
|                                                                                                                         
|8.    Financial Statements and Supplementary Data                                                                        
|                                                                                                                         
|9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                               
|                                                                                                                         
|9A. Controls and Procedures                                                                                              
|                                                                                                                         
|9B. Other Information                                                                                                    
|                                                                                                                         

|PART III                                                                                                   
|-----------------------------------------------------------------------------------------------------------
|                                                                                                           
|10.  Directors, Executive Officers and Corporate Governance of the Registrant                              
|                                                                                                           
|11.  Executive Compensation                                                                                
|                                                                                                           
|12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder 
       Matters
|                                                                                                           
|13.  Certain Relationships and Related Transactions, and Director Independence                             
|                                                                                                           
|14.  Principal Accountant Fees and Services                                                                

---





|PART IV                                        
|-----------------------------------------------
|                                               
|15.  Exhibits and Financial Statement Schedules
|                                               
|Schedule II ‐ Valuation and Qualifying Accounts
|                                               
|Signatures                                     
|                                               
|Exhibit Index                                  
|                                               

---







|DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS                                                                           
|-------------------------------------------------------------------------------------------------------------------------
|                                                                                                                         
|The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.
|                                                                                                                         
|Wisconsin Electric Subsidiary and Affiliates                                                                             
|                                                                                                                         
|Primary Subsidiary and Affiliates                                                                                        
|                                                                                                                         
|                                                                                                                         
|Bostco                                                                                                                   
|Edison Sault                                                                                                             
|We Power                                                                                                                 
|Wisconsin Gas                                                                                                            
|Wisconsin Energy                                                                                                         
|                                                                                                                         
|Significant Assets                                                                                                       
|                                                                                                                         
|                                                                                                                         
|OC 1                                                                                                                     
|OC 2                                                                                                                     
|Point Beach                                                                                                              
|PWGS                                                                                                                     
|PWGS 1                                                                                                                   
|PWGS 2                                                                                                                   
|                                                                                                                         
|Other Affiliates                                                                                                         
|                                                                                                                         
|                                                                                                                         
|ATC                                                                                                                      
|Guardian                                                                                                                 
|NMC                                                                                                                      
|                                                                                                                         
|                                                                                                                         
|Federal and State Regulatory Agencies                                                                                    
|                                                                                                                         
|                                                                                                                         
|DOA                                                                                                                      
|DOE                                                                                                                      
|EPA                                                                                                                      
|FAA                                                                                                                      
|FERC                                                                                                                     
|IRS                                                                                                                      
|MPSC                                                                                                                     
|NRC                                                                                                                      
|PSCW                                                                                                                     
|SEC                                                                                                                      
|WDNR                                                                                                                     
|                                                                                                                         
|                                                                                                                         
|Environmental Terms                                                                                                      
|                                                                                                                         
|                                                                                                                         
|Act 141                                                                                                                  
|Air Permit                                                                                                               
|BART                                                                                                                     
|BTA                                                                                                                      
|CAIR                                                                                                                     
|CAMR                                                                                                                     
|CAVR                                                                                                                     
|CERCLA                                                                                                                   
|CO2                                                                                                                      
|CWA                                                                                                                      

---



|DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS ‐ (Cont'd)                                                                
|-------------------------------------------------------------------------------------------------------------------------
|                                                                                                                         
|The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.
|                                                                                                                         
|NAAQS                                                                                                                    
|NOx                                                                                                                      
|PM 2.5                                                                                                                   
|RI/FS                                                                                                                    
|SO2                                                                                                                      
|WPDES                                                                                                                    
|                                                                                                                         
|                                                                                                                         
|Other Terms and Abbreviations                                                                                            
|                                                                                                                         
|                                                                                                                         
|Compensation Committee                                                                                                   
|CPCN                                                                                                                     
|D&D Fund                                                                                                                 
|Energy Policy Act                                                                                                        
|FPL                                                                                                                      
|FTRs                                                                                                                     
|GCRM                                                                                                                     
|GDP                                                                                                                      
|LLC                                                                                                                      
|LMP                                                                                                                      
|LSEs                                                                                                                     
|MAIN                                                                                                                     
|MISO                                                                                                                     
|MISO Midwest Market                                                                                                      
|Moody's                                                                                                                  
|NEIL                                                                                                                     
|PJM                                                                                                                      
|PTF                                                                                                                      
|PUHCA 1935                                                                                                               
|PUHCA 2005                                                                                                               
|RTO                                                                                                                      
|S&P                                                                                                                      
|Yellowcake                                                                                                               
|                                                                                                                         
|                                                                                                                         
|Measurements                                                                                                             
|                                                                                                                         
|                                                                                                                         
|Btu                                                                                                                      
|Dth                                                                                                                      
|kW                                                                                                                       
|kWh                                                                                                                      
|MW                                                                                                                       
|MWh                                                                                                                      
|Watt                                                                                                                     
|                                                                                                                         
|                                                                                                                         
|Accounting Terms                                                                                                         
|                                                                                                                         
|                                                                                                                         
|AFUDC                                                                                                                    
|APB                                                                                                                      
|ARO                                                                                                                      
|CWIP                                                                                                                     

---





|DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS ‐ (Cont'd)                                                                
|-------------------------------------------------------------------------------------------------------------------------
|                                                                                                                         
|The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.
|                                                                                                                         
|FASB                                                                                                                     
|FIN                                                                                                                      
|FSP                                                                                                                      
|GAAP                                                                                                                     
|OPEB                                                                                                                     
|SAB                                                                                                                      
|SFAS                                                                                                                     
|                                                                                                                         
|                                                                                                                         
|Accounting Pronouncements                                                                                                
|                                                                                                                         
|                                                                                                                         
|FIN 46                                                                                                                   
|FIN 46R                                                                                                                  
|FIN 47                                                                                                                   
|FIN 48                                                                                                                   
|FSP SFAS 106‐2                                                                                                           
|FSP FIN 46R‐6                                                                                                            
|SAB 108                                                                                                                  
|SFAS 71                                                                                                                  
|SFAS 87                                                                                                                  
|SFAS 88                                                                                                                  
|SFAS 106                                                                                                                 
|SFAS 109                                                                                                                 
|SFAS 115                                                                                                                 
|SFAS 123                                                                                                                 
|SFAS 123R                                                                                                                
|SFAS 132R                                                                                                                
|SFAS 133                                                                                                                 
|SFAS 143                                                                                                                 
|SFAS 148                                                                                                                 
|SFAS 149                                                                                                                 
|SFAS 157                                                                                                                 
|SFAS 158                                                                                                                 
|                                                                                                                         

---



CAUTIONARY STATEMENT REGARDING FORWARD‐LOOKING INFORMATION

Certain statements contained in this report and other documents or oral presentations are "forward‐looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements.  Readers are cautioned not to place undue reliance on these forward‐looking statements.  Forward‐looking statements include, among other things, statements concerning management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, the proposed sale of Point Beach, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters.  In some cases, forward‐looking statements may be identified by reference to a future period or periods or by the use of forward‐looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms.

Actual results may differ materially from those set forth in forward‐looking statements.  In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward‐looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:

- Factors affecting utility operations such as unusual weather conditions; catastrophic weather‐related or terrorism‐related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, nuclear fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.

- Regulatory factors such as unanticipated changes in rate‐setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission's regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the regulations of the United States Environmental Protection Agency as well as the Wisconsin Department of Natural Resources, the Michigan Department of Natural Resources or the Michigan Department of Environmental Quality, including but not limited to regulations relating to the release of emissions from fossil‐fueled power plants such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates or mercury, water quality and lead paint; and regulations relating to the intake and discharge of water; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid‐based energy market; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

- The changing electric and gas utility environment as market‐based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.

- Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc. bid‐based energy market that started in April 2005.

- Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.

- Factors related to the proposed sale of our Point Beach Nuclear Plant including receipt of the necessary approvals by various regulatory agencies, including the United States Nuclear Regulatory Commission, the Public Service Commission of Wisconsin, the Michigan Public Service Commission and the Federal Energy

---



- Factors which impede execution of Wisconsin Energy Corporation's Power the Future strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges, local opposition to siting of new generating facilities, construction risks, including the adverse interpretation or enforcement of permit conditions by the permitting agencies, and obtaining the investment capital from outside sources necessary to implement the strategy.

- Changes in social attitudes regarding the utility and power industries.

- Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.

- The cost and other effects of legal and administrative proceedings, settlements, investigations and claims and changes in those matters.

- Factors affecting the availability or cost of capital such as: changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or our subsidiary; or security ratings.

- Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price‐Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.

- Implementation of the Energy Policy Act of 2005 and the effect of state level proceedings and the development of regulations by federal and other agencies, including the Federal Energy Regulatory Commission.

- Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission and the Public Company Accounting Oversight Board.

- Unanticipated technological developments that result in competitive disadvantages and create the potential for impairment of existing assets.

- Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents.

We expressly disclaim any obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise.

---

PART I

|ITEM 1. | BUSINESS
|------- | --------



INTRODUCTION



Wisconsin Electric Power Company, a wholly‐owned subsidiary of Wisconsin Energy, was incorporated in the State of Wisconsin in 1896.  We maintain our principal executive offices in Milwaukee, Wisconsin.  Unless qualified by their context when used in this document, the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary.

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment.  We serve approximately 1,102,200 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 452,600 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin.  For further financial information about our business segments, see Results of Operations in Item 7 and Note O ‐‐ Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.

Wisconsin Energy is also the parent company of Wisconsin Gas, a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault, an electric utility which serves customers in the Upper Peninsula of Michigan; and We Power, an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's PTF strategy, which is described further in this report.  We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies".

PTFStrategy:   In September 2000, Wisconsin Energy announced its PTFstrategy to improve the supply and reliability of electricity in Wisconsin.  As part of the PTF strategy, Wisconsin Energy is: (1) investing in new natural gas‐fired and coal‐fired electric generating facilities, (2) upgrading our existing electric generating facilities and (3) investing in upgrades of our existing energy distribution system.  Additional information concerning PTF may be found below under Utility Operations as well as in Item 7.

Other:    Bostco is our non‐utility subsidiary that develops and invests in real estate.  As of December 31, 2006, Bostco had $39.5 million of assets.

Our annual and periodical filings to the SEC are available, free of charge, through our Internet website www.wisconsinenergy.com.  These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.



UTILITY OPERATIONS



ELECTRIC UTILITY OPERATIONS

We are the largest electric utility in the State of Wisconsin.  We generate and distribute electric energy in a territory in southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and in the Upper Peninsula of Michigan.

Effective April 1, 2005, we began to participate in the MISO Midwest Market which changed how our generating units are dispatched and how we buy and sell power.  For further information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Electric Sales

We are authorized to provide retail electric service in designated territories in the State of Wisconsin, as established by indeterminate permits, CPCNs or boundary agreements with other utilities, and in certain territories in the State of Michigan pursuant to franchises granted by municipalities.  We also sell wholesale electric power within the MISO Midwest Market.

---

Our electric energy sales to all classes of customers totaled approximately 31.4 million MWh during 2006 and approximately 32.0 million MWH during 2005.  Approximately 0.4 million of MWh sales during 2006 and 2005 were to Edison Sault.  We had approximately 1,102,200 electric customers at December 31, 2006 and 1,092,400 electric customers at December 31, 2005.

Electric Sales Growth:   We presently anticipate total retail and municipal electric kWh sales of our electric utility will grow at an annual rate of 1% to 1.5% over the next five years.  This estimate excludes the mine contracts (see Legal Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7), and assumes moderate growth in the economy of our electric utility service territories and normal weather.  We also anticipate that our peak electric demand will grow at a rate of 1.5% to 2.0% over the next five years.

Sales to Large Electric Retail Customers:   We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, as well as to large retail chains.

Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan.  We currently have special negotiated power‐sales contracts with these mines that expire in December 2007.  The combined electric energy sales to the two mines accounted for 6.3% and 7.2% of our total electric utility energy sales during 2006 and 2005, respectively.  In 2005, the mines notified us that they are disputing certain billings and they have placed the disputed amounts in escrow.  We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contract.  Arbitration hearings related to this matter are scheduled for August 2007.  Although it is currently uncertain, we anticipate that we will provide power to the mines under the terms of one or more regulated tariffs to be approved by the MPSC beginning January 1, 2008.  For further information, see Legal Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Sales to Wholesale Customers:   During 2006, we sold wholesale electric energy to two municipally owned systems, two rural cooperatives and one municipal joint action agency located in the states of Wisconsin and Michigan.  We also made wholesale electric energy sales to 34 other public utilities and power marketers throughout the region under rates approved by FERC.  Wholesale sales accounted for approximately 10.4% of our total electric energy sales and 5.7% of total electric operating revenues during 2006, compared with 9.3% of total electric energy sales and 5.5% of total electric operating revenues during 2005.

Electric System Reliability Matters:  Electric energy sales are impacted by seasonal factors and varying weather conditions from year‐to‐year.  As a summer peaking utility, we reached our all‐time electric peak demand obligation of 6,376 MW on July 31, 2006.  The summer period is the most relevant period for capacity planning purposes for us as a result of cooling load.  Prior to 2006, we were a member of the MAIN reliability council, whose guidelines required a minimum 14% planning reserve margin for the short‐term (up to one year ahead).  Effective January 1, 2006, we became a member of ReliabilityFirst Corporation, a successor council encompassing most of the East Central Area Reliability Council and Mid‐Atlantic Area Council and a portion of MAIN.  ReliabilityFirst Corporation has not yet established guidelines in this area but members are expected to adhere to the guidelines of their predecessor councils until new guidelines are established.  We must also adhere to PSCW guidelines requiring an 18% planning reserve margin and we expect to be in compliance with ReliabilityFirst Corporation guidelines when they are established.  The MPSC has not established guidelines in this area.

We had adequate capacity to meet all of our firm electric load obligations during 2006 and expect to have adequate capacity to meet all of our firm obligations during 2007.  For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

---



Electric Supply

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2006, as well as an estimate for 2007.  This information excludes any impact of the proposed sale of Point Beach.



|                | Estimate |  | Actual
|--------------- | -------- |  | ------
|                |          |  |       
|                | 2007     |  | 2006  
|                |          |  |       
|                |          |  |       
|Coal            | 60.9%    |  | 55.5% 
|Nuclear         | 24.8%    |  | 25.7% 
|Hydroelectric   | 1.2%     |  | 1.0%  
|Natural gas (a) | 6.7%     |  | 4.1%  
|                |          |  |       
|Net Generation  | 93.6%    |  | 86.3% 
|Purchased Power | 6.4%     |  | 13.7% 
|                |          |  |       
|Total           | 100.0%   |  | 100.0%
|                |          |  |       
|                |          |  |       
|                |          |  |       



|(a) | Includes PWGS 1, which was placed into service in July 2005.
|--- | ------------------------------------------------------------





Wisconsin Energy's PTFstrategy, which is discussed further in Item 7, includes the addition of 2,320 MW of generating capacity through 2010.  The PTFstrategyincludes two 545 MW natural gas units at our existing site in Port Washington, Wisconsin.  The first unit, which has a current dependable capability of 575 MW, was placed into service in July 2005.  The second unit is expected to be placed in service in 2008.  We Power has begun construction of two 615 MW coal units (of which We Power will own approximately a 515 MW share of each unit) in Oak Creek, Wisconsin adjacent to the site of our existing Oak Creek Power Plant.  We anticipate that the first coal unit will be placed in service in 2009, followed by the second unit in 2010.

We believe that the PTFstrategy will allow us to better manage the mix of fuels used to generate electricity for our customers.  We believe that it is in the best interests of our customers to provide a diverse fuel mix that is expected to maintain a stable, reliable and affordable energy supply in our service territory.



Our net generation, including PWGS 1, totaled 28.7 million MWh during 2006 compared with 28.0 million MWh during 2005 and 29.0 million MWh during 2004.  Net generation as a percent of our total electric energy supply increased in 2006 due to the availability of the PWGS 1 for the entire year and one fewer scheduled nuclear outage in 2006 versus 2005.

Our average fuel and purchased power costs per MWh by fuel type for the years ended December 31, are shown below.



|                             |  | 2006    |  | 2005    |  | 2004  
|---------------------------- |  | ------- |  | ------- |  | ------
|                             |  |         |  |         |  |       
|                             |  |         |  |         |  |       
|Coal                         |  | $18.30  |  | $14.74  |  | $14.18
|Nuclear                      |  | $5.23   |  | $5.06   |  | $4.68 
|Natural Gas ‐ Combined Cycle |  | $66.30  |  | $84.77  |  | ‐     
|Natural Gas ‐ Peaking Units  |  | $136.24 |  | $125.67 |  | $95.16
|Purchased Power              |  | $49.43  |  | $55.47  |  | $37.49

We use natural gas to fuel our peaking units that are designed to run for short durations.  The PWGS natural gas‐fired units that are part of the PTF strategy are combined cycle facilities that are designed to run for longer durations and at a lower operating cost as compared to a peaking unit.

Historically, the fuel costs for coal and nuclear generation have been under long‐term contracts, which helped with price stability.  In 2006, we entered into new coal contracts to replace certain contracts that expired during 2006.  Coal and associated transportation services have seen greater volatility in pricing than typically experienced in these markets due to increases in the domestic and world‐wide demand for coal and the impacts of higher diesel costs in

---

The costs for natural gas and purchased power, which is primarily natural gas‐fired, are more volatile and have experienced significant increases since 2002.  Natural gas costs have increased significantly because the supply of natural gas in recent years has not kept pace with the demand for natural gas.  Beginning in late 2003 and concurrent with the approval of the PSCW, we established a hedging program to help manage our natural gas price risk.  This hedging program is generally implemented on an 18 month forward‐looking basis.  Proceeds related to the natural gas hedging program are reflected in the 2006, 2005 and 2004 average costs of natural gas and purchased power shown above.

Our installed capacity by fuel type for the years ended December 31 is shown below.



|                    |  | Dependable Capability in MW (a)
|------------------- |  | -------------------------------
|                    |  |                                
|                    |  | 2006                           
|                    |  |                                
|                    |  |                                
|Coal                |  | 3,334                          
|Nuclear             |  | 1,036                          
|Natural Gas/Oil (b) |  | 1,750                          
|Hydro               |  | 57                             
|                    |  |                                
|Total               |  | 6,177                          
|                    |  |                                
|                    |  |                                
|                    |  |                                



|(a) | Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year.  The values were established by test and may change slightly from year to year.                                                                                                                                                                                                                 
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|(b) | Approximately 50% of the Natural Gas/Oil units are dual fueled.  The dual fuel facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants.  The increase in 2006 primarily reflects a 30 MW increase in dependable capability at PWGS 1, which was added in 2005, from the 545 MW guaranteed capacity required under the lease.



Coal‐Fired Generation

Coal Supply:   We diversify the coal supply for our power plants by purchasing coal from mines in northern and central Appalachia as well as from various western mines.  During 2007, 96.2% of our projected coal requirements of 12.2 million tons will be under contracts which are not tied to 2007 market pricing fluctuations.  We do not anticipate any problem in procuring our remaining 2007 coal requirements.  Our coal‐fired generation consists of six operating plants with a dependable capability of approximately 3,334 MW.

Following is a summary of the annual tonnage amounts for our principal long‐term coal contracts by the month and year in which the contracts expire.





|Contract
Expiration Date |  | Annual Tonnage
|------------------------ |  | --------------
|                         |  |               
|                         |  | (Thousands)   
|                         |  |               
|Dec. 2007                |  | 0.1           
|Dec. 2008                |  | 4,850.0       
|Dec. 2009                |  | 6,500.0       





Coal Deliveries:   Approximately 85.7% of our 2007 coal requirements are expected to be delivered by unit trains owned or leased by us.  The unit trains will transport coal for the Oak Creek, Pleasant Prairie and Edgewater Power

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Environmental Matters:   For information regarding emission restrictions, especially as they relate to coal‐fired generating facilities, see Environmental Compliance below.



Nuclear Generation

Point Beach:   We own two 518 MW electric generating units at Point Beach in Two Rivers, Wisconsin.  The operating licenses for Point Beach will expire in October 2030 for Unit 1 and in March 2033 for Unit 2.  In December 2006, we announced that we had reached a definitive agreement to sell Point Beach to an affiliate of FPL.  Under the agreement, FPL will purchase the plant, its nuclear fuel and associated inventories for approximately $998 million, subject to closing price adjustments, and it will also assume the obligation to decommission the plant.  We also entered into a long‐term power purchase agreement to purchase all of the existing capacity and energy of the plant, which will become effective upon closing of the sale.  This transaction is subject to regulatory review and approval and we anticipate it will close during the third quarter of 2007.  If and when the sale is completed (or earlier if an interim operating agreement with FPL is activated by us), Point Beach's operating licenses would transfer from NMC to FPL.  Until the transaction is completed, we continue to own Point Beach and retain exclusive rights to the energy generated by the plant, as well as financial responsibility for the safe operation, maintenance and decommissioning of Point Beach.  For further information concerning Point Beach, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Nuclear Operations in Item 7 and Note F ‐‐ Nuclear Operations in the Notes to Consolidated Financial Statements in item 8.

Nuclear Management Company:   NMC, owned by our affiliate, WEC Nuclear Corporation and the affiliates of two other unaffiliated investor‐owned utilities in the region, operates Point Beach.  NMC currently operates six nuclear generating units at four sites in the states of Wisconsin, Minnesota and Michigan with a total combined generating capacity of approximately 3,500 MW.  One of the other two unaffiliated investor‐owned utilities has announced the planned sale of their unit.

Nuclear Fuel Supply:   We purchase Yellowcake and contract for its conversion, enrichment and fabrication.  There have been numerous events in the nuclear fuel supply market that have affected the price of uranium concentrates, conversion service and enrichment services.  The price of the fuel commodities has risen steadily since the fourth quarter of 2003 and we anticipate that the price will continue to rise due to current demand exceeding current supply.  NMC is continually monitoring the nuclear fuel commodities market to assess current and future commodity pricing and adjusting purchasing strategies to address changes in the market conditions.  We maintain title to the nuclear fuel until fabricated fuel assemblies are delivered to Point Beach; it is then sold to and leased back from the Wisconsin Electric Fuel Trust.  For further information concerning this nuclear fuel lease, see Note G ‐‐ Long‐Term Debt in the Notes to Consolidated Financial Statements in Item 8.

Uranium Requirements:   We require approximately 400,000 to 450,000 pounds of Yellowcake to refuel a generating unit at Point Beach.  Point Beach has staggered fuel cycles that are expected to average approximately 18 months in duration.  The supply of Yellowcake for these refuelings is currently provided through one long‐term contract, which supplies 100% of the annual requirements through 2009.  Contract negotiations through NMC are currently underway that would supply approximately 60% of the Point Beach requirements from 2010 to 2016.

Conversion:   We had conversion services supply from a share of an NMC fleet contract for conversion services and four spot purchase contracts to meet 100% of our conversion requirements for 2006.  In 2006, an additional NMC fleet contract for conversion services was signed to supply approximately 100% of the Point Beach requirements through 2010 and approximately 10% of the 2011 requirements.

Enrichment:   Wisconsin Electric effectively has three contracts through NMC that provide for 100% of the required enrichment services for  Point Beach through the year 2009 and approximately 70% of the enrichment services requirements through 2013.

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Fabrication:   Fabrication of fuel assemblies from enriched uranium for Point Beach is covered under a contract with Westinghouse Electric Company, LLC.  The current contract for fabrication services is through 2010 for Unit 1 and 2013 for Unit 2.

Used Nuclear Fuel Storage & Disposal:   For information concerning used nuclear fuel storage and disposal issues, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Nuclear Decommissioning:   We provide for costs associated with the eventual decommissioning of Point Beach through the use of external trust funds.  Payments to these funds, together with investment results, brought the balance in the funds at December 31, 2006 to approximately $881.6 million.  For additional information regarding decommissioning, including the impact of the proposed sale of Point Beach, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Nuclear Operations in Item 7 and Note F ‐‐ Nuclear Operations in the Notes to Consolidated Financial Statements in Item 8.

Nuclear Plant Insurance:   For information regarding nuclear plant insurance, see Note F ‐‐ Nuclear Operations in the Notes to Consolidated Financial Statements in Item 8.



Natural Gas‐Fired Generation

Our natural gas‐fired generation consists of five operating plants with a dependable capability of approximately 1,475 MW at December 31, 2006.  In July 2005, we added PWGS 1, a natural gas‐fired unit with a dependable capability of 575 MW, via a lease from We Power.  A second 545 MW unit at PWGS is expected to come on line in 2008.

We purchase natural gas for these plants on the spot market from gas marketers, utilities and producers and we arrange for transportation of the natural gas to our plants.  We have firm and interruptible transportation, balancing and storage agreements intended to support the plants' variable usage.

The PSCW has approved a program that allows us to hedge up to 75% of our estimated gas usage for electric generation in order to help manage our natural gas price risk.  The costs of this program are included in our fuel and purchased power costs.



Oil‐Fired Generation

Fuel oil is used for the combustion turbines at the Point Beach and Germantown Power Plants units 1‐4.  It is also used for boiler ignition and flame stabilization at the Presque Isle Power Plant.  Our oil‐fired generation has a dependable capability of approximately 275 MW at December 31, 2006.  The natural gas facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants.  Fuel oil requirements are purchased under agreements with suppliers.



Hydroelectric Generation

Our hydroelectric generating system consists of thirteen operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 57 MW at December 31, 2006.  Of these thirteen plants, twelve plants (86 MW of installed capacity) have long‐term licenses from FERC.  The thirteenth plant, with an installed generating capacity of approximately 2 MW, does not require a license.

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Purchase Power Commitments

We enter into short and long‐term purchase power commitments to meet a portion of our anticipated electric energy supply needs.  The following table identifies our purchase power commitments at December 31, 2006 with unaffiliated parties for the next five years:



|Year |  | MW Under 
Purchase Power 
Commitments (a) | 
|---- |  | ----------------------------------------- | 
|     |  |                                           | 
|     |  |                                           | 
|2007 |  | 1,148                                     | 
|2008 |  | 698                                       | 
|2009 |  | 580                                       | 
|2010 |  | 580                                       | 
|2011 |  | 550                                       | 



|(a) | MW do not include leased generation from PTF units.
|--- | ---------------------------------------------------



The majority of these purchase power commitments are tolling arrangements whereby we are responsible for the procurement, delivery and cost of natural gas fuel related to specific units identified in the contracts.  A small amount of these purchases are tied to the costs of natural gas.

In addition, as part of Wisconsin Energy's PTF strategy, we will be leasing four new operating units from We Power under long‐term leases that have been approved by the PSCW, our primary regulator.  We will be responsible for all of the operating costs, including fuel, of the PTF units once they are placed in service and we anticipate that we will recover the operating costs of these plants in rates.  The first of the four generating units, PWGS 1, was placed in service in July 2005 and is being leased to us by We Power.  The lease‐guaranteed capacity for PWGS 1 is 545 MW and the current dependable capability is 575 MW.  PWGS 2 is expected to be operational in 2008, with a lease‐guaranteed capacity of 545 MW.  OC 1 and OC 2 are expected to be operational in 2009 and 2010, each with a total lease‐guaranteed capacity of 615 MW, of which 515 MW will represent our approximate 83% share.

We have also entered into a long‐term power purchase agreement with FPL that is contingent upon the sale of Point Beach.  This agreement allows us to receive all of the existing capacity and energy of the Point Beach units.  We will have the unilateral option, subject to PSCW direction, to select a term for the power purchase agreement of either (i) an estimated 23 years for Unit 1 and 26 years for Unit 2, or (ii) 16 years for Unit 1 and 17 years for Unit 2.  This agreement is subject to approval by various regulatory authorities.



Electric Transmission and Energy Markets

American Transmission Company:   ATC owns, maintains, monitors and operates electric utility transmission in Wisconsin, Michigan and Illinois.  ATC's sole business is to provide reliable, economic electric transmission service to all customers in a fair and equitable manner.  ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without favoring any market participant.  ATC is regulated by FERC for all rate terms and conditions of service and is a transmission‐owning member of MISO.  As of February 1, 2002, operational control of ATC's transmission system was transferred to MISO, and we are a non‐transmission owning member and customer of MISO.

We owned approximately 25.8% and 29.4% of ATC as of December 31, 2006 and 2005.  Our ownership has decreased from December 31, 2005 as other owners have invested additional equity in ATC related to specific, large construction projects subject to their contractual rights.

MISO:   In connection with its status as a FERC approved RTO, MISO developed a bid‐based energy market, the MISO Midwest Market, which was implemented on April 1, 2005.  For further information on MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

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Renewable Electric Energy

Wisconsin Energy's PTF strategy includes a commitment to significantly increase the amount of renewable energy generation we utilize.  In addition, we have an "Energy For Tomorrow®" renewable energy program to provide our customers the opportunity to purchase energy from renewable resources.  In March 2006, Wisconsin enacted new public benefits legislation, Act 141.  Act 141 changes the renewable energy requirements for utilities.  Act 141 requires Wisconsin utilities to provide 2% more of their total retail energy from renewable resources than their current levels by 2010, and 6% more renewable energy than their current levels by 2015.  Act 141 establishes a statewide goal that 10% of all electricity in Wisconsin be generated by renewable resources by December 31, 2015.  For further information on Act 141 and current renewable projects, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Rates and Regulatory Matters ‐ Renewables, Efficiency and Conservation and Rates and Regulatory Matters ‐ Wind Generation in Item 7.

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Electric Utility Operating Statistics

The following table shows certain electric utility operating statistics from 2002 to 2006 for electric operating revenues, MWh sales and customer data.



|SELECTED CONSOLIDATED ELECTRIC UTILITY OPERATING DATA
|-----------------------------------------------------
|                                                     
|                                                     
|Year Ended December 31                               
|                                                     
|                                                     
|Operating Revenues (Millions)                        
|Residential                                          
|Small Commercial/Industrial                          
|Large Commercial/Industrial                          
|Other ‐ Retail/Municipal                             
|Resale ‐ Utilities                                   
|Other Operating Revenues                             
|                                                     
|Total Operating Revenues                             
|                                                     
|                                                     
|                                                     
|                                                     
|MWh Sales (Thousands)                                
|Residential                                          
|Small Commercial/Industrial                          
|Large Commercial/Industrial                          
|Other ‐ Retail/Municipal                             
|Resale ‐ Utilities                                   
|                                                     
|Total Sales                                          
|                                                     
|                                                     
|                                                     
|                                                     
|Customers ‐ End of Year (Thousands)                  
|Residential                                          
|Small Commercial/Industrial                          
|Large Commercial/Industrial                          
|Other                                                
|                                                     
|Total Customers                                      
|                                                     
|                                                     
|                                                     
|                                                     
|Customers ‐ Average (Thousands)                      
|                                                     
|Degree Days (a)                                      
|Heating (6,663 Normal)                               
|Cooling (716 Normal)                                 



|(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin.  Normal degree days are based upon a 20‐year moving average.
|---------------------------------------------------------------------------------------------------------------------------------------



GAS UTILITY OPERATIONS

We are authorized to provide retail gas distribution service in designated territories in the State of Wisconsin, as established by indeterminate permits, CPCNs or boundary agreements with other utilities.  We also transport customer‐owned gas.  Our gas utility operates in three distinct service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin.



Gas Deliveries

Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers.  Annual gas sales are also impacted by the variability of winter temperatures.

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Total gas therms delivered, including customer‐owned transported gas, were approximately 812.6 million therms during 2006, a 10.0% decrease compared with 2005.  At December 31, 2006, we were transporting gas for approximately 400 customers who purchased gas directly from other suppliers.  Transported gas accounted for approximately 37% of the total volumes delivered during 2006, 39% during 2005, and 34% during 2004.  We had approximately 452,600 gas customers at December 31, 2006, an increase of approximately 1.4% since December 31, 2005.

Our maximum daily send‐out during 2006 was 590,843 Dth on February 18, 2006.  A Dth is equivalent to ten therms or one million Btu.

Sales to Large Gas Customers:   We provide gas utility service to a diversified base of industrial customers who are largely within our electric service territory.  Major industries served include the paper, food products and fabricated metal products industries.  Fuel used for our electric energy supply represents our largest transportation customer.

Gas Deliveries Growth:   We currently forecast total retail therm deliveries (excluding natural gas deliveries for generation) to stay flat over the five‐year period ending December 31, 2011 as new customer additions are expected to be offset by a reduction in the average use per customer.  This forecast reflects a current year normalized sales level and assumes moderate growth in the economy of our gas utility service territories and normal weather.



Competition

Competition in varying degrees exists between natural gas and other forms of energy available to consumers.  Many of our large commercial and industrial customers are dual‐fuel customers that are equipped to switch between natural gas and alternate fuels.  We are allowed to offer lower‐priced gas sales and transportation services to dual fuel customers.  Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to their facilities.  We earn substantially the same margin (difference between revenue and cost of gas) whether we sell and transport gas to customers or only transport their gas.

Our ability to maintain our share of the industrial dual‐fuel market (the market that is equipped to use gas or other fuels) depends on our success and the success of third‐party gas marketers in obtaining long‐term and short‐term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively‐priced transportation service for those customers that desire to buy their own gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the gas industry.  For information concerning proceedings by the PSCW to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the gas industry, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.  While the gas utility distribution function is expected to remain a highly regulated, monopoly function, the sales of the natural gas commodity and related services are expected to remain subject to competition from third parties.  It remains uncertain if and when the current economic disincentives for small customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to our smaller firm customers.



Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers despite periods of severe cold and unseasonably warm weather.

Pipeline Capacity and Storage:   The interstate pipelines serving Wisconsin originate in three major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico and western Canada.  We have contracted for long‐term firm capacity from each of these areas.  This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolios and that Canada represents an important long‐term source of reliable, competitively‐priced gas.

Because of the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan.  Storage capacity enables us to manage significant changes in daily demand and to optimize our overall gas supply and capacity costs.  We generally inject gas into storage during the

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We also maintain storage in the Southeast production areas, as well as in our market area.  This storage capacity is designed to deliver gas when other supplies cannot be delivered during extremely cold weather in the producing areas.  We hold firm daily transportation and storage capacity entitlements from pipelines and other service providers under long‐term contracts.

Term Gas Supply:   We have contracts for firm supplies with terms in excess of 30 days with suppliers for gas acquired in the Joliet, Illinois market hub and in the three producing areas discussed above.  The pricing of the term contracts is based upon first of the month indices.  Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak day demand.

Secondary Market Transactions:   Capacity release is a mechanism by which pipeline long‐line and storage capacity and gas supplies under contract can be resold in the secondary market.  Local distribution companies, like our gas operations, must contract for capacity and supply sufficient to meet the firm peak day demand of our customers.  Peak or near peak demand days generally occur only a few times each year.  Capacity release facilitates higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and gas supply.  Through pre‐arranged agreements and day‐to‐day electronic bulletin board postings, interested parties can purchase this excess capacity and supply.  The proceeds from these transactions are passed through to ratepayers, subject to our GCRM pursuant to which we have an opportunity to share in the cost savings.  See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Rates and Regulatory Matters in Item 7 for information on the GCRM.  During 2006, we continued our active participation in the capacity release market.

Spot Market Gas Supply:   We expect to continue to make gas purchases in the 30‐day spot market as price and other circumstances dictate.  We have supply relationships with a number of sellers from whom we purchase spot gas.

Hedging Gas Supply Prices:   We have PSCW approval to hedge (i) up to 45% of planned flowing gas supply using NYMEX based natural gas options, (ii) up to 15% of planned flowing gas supply using NYMEX based natural gas future contracts and (iii) up to 35% of planned storage withdrawals using NYMEX based natural gas options.  Those approvals allow us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) through our purchase gas adjustment mechanism.  Hedge targets (volumes) are provided annually to the PSCW as part of our five‐year gas supply plan filing.



To the extent that opportunities develop and our physical supply operating plans will support them, we also have PSCW approval to utilize NYMEX based natural gas derivatives to capture favorable forward market price differentials.  That approval provides for 100% of the related proceeds to accrue to our GCRM.

Guardian Pipeline:   Prior to April 2006, Wisconsin Energy had a one‐third interest in Guardian.  Guardian owns an interstate natural gas pipeline that runs from the Joliet, Illinois area to southeastern Wisconsin.  In April 2006, Wisconsin Energy sold its one‐third interest in Guardian to an unaffiliated entity.  During 2006, Guardian announced a plan to extend their pipeline by approximately 110 miles from southeastern Wisconsin to Green Bay, Wisconsin.  We have committed to purchase approximately 202,000 Dth per day of capacity on this extension through October 2023.  In addition, Wisconsin Gas has extended its commitment to purchase 650,000 Dth per day of capacity on the original pipeline until December 2022.  Under a PSCW‐approved agreement, we have purchased some of this capacity from Wisconsin Gas when they have an excess, and we expect to continue to do so.  In October 2006, along with Wisconsin Gas and in connection with the Guardian extension, we filed a joint application with the PSCW to construct approximately 13 miles of pipeline laterals (approximately 10 miles of which would be owned by us) to connect our gas distribution system to the proposed Guardian extension.  The Guardian extension is projected to be operational in November 2008.

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Gas Utility Operating Statistics

The following table shows certain gas utility operating statistics from 2002 to 2006 for gas operating revenues, therms delivered and customer data.



|SELECTED CONSOLIDATED GAS UTILITY OPERATING DATA
|------------------------------------------------
|                                                
|                                                
|Year Ended December 31                          
|                                                
|                                                
|Operating Revenues (Millions)                   
|Residential                                     
|Commercial/Industrial                           
|Interruptible                                   
|                                                
|Total Retail Gas Sales                          
|Transported Gas                                 
|Other Operating Revenues                        
|                                                
|Total Operating Revenues                        
|                                                
|                                                
|                                                
|                                                
|Therms Delivered (Millions)                     
|Residential                                     
|Commercial/Industrial                           
|Interruptible                                   
|                                                
|Total Retail Gas Sales                          
|Transported Gas                                 
|                                                
|Total Therms Delivered                          
|                                                
|                                                
|                                                
|                                                
|Customers ‐ End of Year (Thousands)             
|Residential                                     
|Commercial/Industrial                           
|Transported Gas                                 
|                                                
|Total Customers                                 
|                                                
|                                                
|                                                
|                                                
|Customers ‐ Average (Thousands)                 
|                                                
|Degree Days (a)                                 
|Heating (6,663 Normal)                          



|(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin.  Normal degree days are based upon a 20‐year moving average.
|---------------------------------------------------------------------------------------------------------------------------------------



STEAM UTILITY OPERATIONS

Our steam utility generates, distributes and sells steam supplied by our Valley and Milwaukee County Power Plants.  We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee.  Steam is supplied to this system from our Valley Power Plant, a coal‐fired cogeneration facility.  We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.

Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions.  During 2006, the steam utility had $27.2 million of operating revenues from the sale of 2,812 million pounds of steam compared with $23.5 million of operating revenues from the sale of 2,908 million pounds of steam during 2005.  As of December 31, 2006 and 2005, steam was used by approximately 460 customers for processing, space heating, domestic hot water and humidification.

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UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Rates and Regulatory Matters in Item 7.



REGULATION

We were an exempt holding company under Section 3(a)(1) of PUHCA 1935 and Rule 2 thereunder and, accordingly, were exempt from that law's provisions other than with respect to certain acquisitions of securities of a public utility.  In August 2005, President Bush signed into law the Energy Policy Act.  The Energy Policy Act repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to FERC.  We were required to notify FERC of our status as a holding company by reason of our ownership interest in ATC and to seek from FERC the exempt status similar to that held under PUHCA 1935.  In March 2006, we filed with FERC notification of our status as a holding company as required and a request for exempt status similar to that held under PUHCA 1935.  In June 2006, we received notice from FERC confirming our status as a holding company as required under FERC regulations implementing PUCHA 2005 and granting exempt status similar to that held under PUHCA 1935.  For information on how rates are set see Rates and Regulatory Matters in Item 7.

We are subject to the Energy Policy Act and the corresponding regulations developed by certain federal agencies.  The Energy Policy Act, among other things, repeals PUHCA 1935 making electric utility industry consolidation more possible, authorizes FERC to review proposed mergers and the acquisition of generation facilities, changes FERC regulatory scheme applicable to qualifying co‐generation facilities and modifies certain other aspects of energy regulations and Federal tax policies applicable to us.  Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by FERC, which will establish mandatory electric reliability standards, replacing the current voluntary standards developed by the North American Electric Reliability Corporation, and will have the authority to levy monetary sanctions for failure to comply with the new standards.

We are subject to the regulation of the PSCW as to retail electric, gas, and steam rates in the State of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters.  We are also subject to regulation of the PSCW as to certain levels of short‐term debt obligations.  We are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the State of Michigan as noted above except as to issuance of securities, construction of certain new facilities, levels of short‐term debt obligations and advance approval of transactions with affiliates.  Our hydroelectric facilities are regulated by FERC.  We are subject to regulation of FERC with respect to wholesale power service and accounting.

The following table compares the source of our operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2006.



|                                 | 2006                  |  | 2005    |  | 2004    
|-------------------------------- | --------------------- |  | ------- |  | --------
|                                 |                       |  |         |  |         
|                                 | Amount                |  | Percent |  | Amount  
|                                 |                       |  |         |  |         
|                                 | (Millions of Dollars)
|Wisconsin                        |                       |  |         |  |         
|Electric Utility ‐ Retail        | $2,222.4              |  | 71.3%   |  | $2,049.7
|Gas Utility ‐ Retail             | 590.0                 |  | 18.9%   |  | 593.6   
|Steam Utility ‐ Retail           | 27.2                  |  | 0.9%    |  | 23.5    
|                                 |                       |  |         |  |         
|Total                            | 2,839.6               |  | 91.1%   |  | 2,666.8 
|Michigan                         |                       |  |         |  |         
|Electric Utility ‐ Retail        | 135.4                 |  | 4.3%    |  | 143.2   
|FERC                             |                       |  |         |  |         
|Electric Utility ‐ Wholesale     | 141.7                 |  | 4.6%    |  | 128.0   
|                                 |                       |  |         |  |         
|Total Utility Operating Revenues | $3,116.7              |  | 100.0%  |  | $2,938.0
|                                 |                       |  |         |  |         
|                                 |                       |  |         |  |         
|                                 |                       |  |         |  |         





For information concerning the implementation of full electric retail competition in the State of Michigan effective January 1, 2002, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

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Operation and construction relating to Point Beach are subject to regulation by the NRC.  Our operations are also subject to regulations, where applicable, of the EPA, the WDNR, the Michigan Department of Natural Resources and the Michigan Department of Environmental Quality.

Public Benefits and Renewables

In March 2006, Wisconsin enacted new public benefits legislation, Act 141.  Act 141 changes the renewable energy requirements for utilities.  Act 141 requires Wisconsin utilities to provide 2% more of their total retail energy from renewable resources than their current levels by 2010, and 6% more renewable energy than their current levels by 2015.  Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the DOA back to the utilities and/or contracted third parties.  In addition, Act 141 requires that 1.2% of utilities' annual operating revenues be used to fund these programs.  For additional information on Act 141 and current renewable projects see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Rates and Regulatory Matters ‐ Renewables, Efficiency and Conservation and Rates and Regulatory Matters ‐ Wind Generation in Item 7.





ENVIRONMENTAL COMPLIANCE

Environmental Expenditures

Expenditures for environmental compliance and remediation issues are included in anticipated capital expenditures described in Liquidity and Capital Resources in Item 7.  For discussion of additional environmental issues, see Environmental Matters in Item 3.  For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Our compliance with federal, state and local environmental protection requirements resulted in capital expenditures of approximately $79 million in 2006 compared with $153 million in 2005.  Expenditures incurred during 2006 primarily included costs associated with the installation of pollution abatement facilities at our power plants.  These expenditures are expected to approximate $39 million during 2007, reflecting NOx, SO2 and other pollution control equipment needed to comply with various rules promulgated by the EPA.

Operation, maintenance and depreciation expenses for our fly ash removal equipment and other environmental protection systems are estimated to have been approximately $49 million during 2006 and $40 million during 2005.

Solid Waste Landfills

We provide for the disposal of non‐ash related solid wastes and hazardous wastes through licensed independent contractors, but federal statutory provisions impose joint and several liability on the generators of waste for certain cleanup costs.  Currently there are no active cases.

Coal‐Ash Landfills

Some early designed and constructed coal‐ash landfills may allow the release of low levels of constituents resulting in the need for various levels of remediation.  Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions.  For additional information, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.  Sites currently undergoing remediation and/or monitoring include the following:

Lakeside Property:   During 2001, we completed an investigation of property that was used primarily for coal storage, fuel oil transport and coal ash disposal in support of the former Lakeside Power Plant in St. Francis, Wisconsin.  Excavation and utilization of residual coal at the site, slope stabilization and cover construction have been completed.  Currently, discussions are taking place with neighbors and other interested parties to determine the ultimate use of the remediated property and some other adjacent land that we also own.

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Oak Creek North Landfill:   Groundwater impairments at this landfill, located in the City of Oak Creek, Wisconsin, prompted us to investigate, during 1998, the condition of the existing cover and other conditions at the site.  Surface water drainage improvements were implemented at this site during 1999 and 2000, which are expected to eliminate ash contact with water and remove unwanted ponding of water.  The approved remediation plan was coordinated with activities associated with the construction of the new units.  Currently there is a temporary cap installed and being used as laydown area and parking.  When construction activities are completed, a permanent cap will be installed.

Manufactured Gas Plant Sites

We are reviewing and addressing environmental conditions at a number of former manufactured gas plant sites.  See Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

Air Quality

See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Environmental Matters in Item 7 for additional information concerning Air Quality.

Clean Water Act

See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Environmental Matters in Item 7 for additional information concerning the CWA.



OTHER

Research and Development:   We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations.  Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.

Employees:   At December 31, 2006, we had 4,597 total employees, of which 3,170 were represented under labor agreements.  We had the following employees represented under labor agreements with the following bargaining units as of December 31, 2006:



|                                                                                                                                                                        | Number of Employees |  | Expiration Date of Current Labor Agreement
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------- |  | ------------------------------------------
|                                                                                                                                                                        |                     |  |                                           
|Local 2150 of International     Brotherhood of Electrical Workers                                                                                                       | 2,337               |  | August 15, 2007                           
|Local 317 of International Union of     Operating Engineers (a)                                                                                                         | 456                 |  | September 30, 2006                        
|Local 12005 of United Steel Workers     of America (b)                                                                                                                  | 165                 |  | November 1, 2008                          
|Local 510 of International Brotherhood     of Electrical Workers                                                                                                        | 161                 |  | April 30, 2007                            
|Local 2‐0111 of Paper, Allied‐    Industrial Chemical & Energy     Workers International Union (b)                                                                      | 51                  |  | November 3, 2008                          
|                                                                                                                                                                        |                     |  |                                           
|Total                                                                                                                                                                   | 3,170               |  |                                           
|                                                                                                                                                                        |                     |  |                                           
|                                                                                                                                                                        |                     |  |                                           
|                                                                                                                                                                        |                     |  |                                           
|                                                                                                                                                                        |                     |  |                                           
|(a)  Labor agreement was effective October 1, 2003 through September 30, 2006.  It remains in effect since settlement has not yet been reached as of December 31, 2006.
|                                                                                                                                                                       
|(b)  Effective January 1, 2006, these bargaining units became a part of Local 2006.  These former locals are now individual bargaining units of Local 2006.            

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|ITEM 1A. | RISK FACTORS
|-------- | ------------

Our business is significantly impacted by governmental regulation.

We are subject to significant state, local and federal governmental regulation.  We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the State of Wisconsin, standards of service, issuance of securities, short‐term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters.  In addition, we are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the State of Michigan, except as to issuance of securities, construction of certain new facilities, levels of short‐term debt obligations and advance approval of transactions with affiliates.  Further, our hydroelectric facilities are regulated by FERC, and FERC also regulates our wholesale power service practices.  Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.

We are obligated in good faith to comply with any applicable governmental rules and regulations.  If it is determined that we failed to comply with any applicable rules or regulations, whether through new interpretations or applications of the regulations or otherwise, we may be liable for customer refunds, penalties or other amounts, which could materially adversely effect our results of operations and financial condition.

We estimate that approximately 89% of our electric revenues are regulated by the PSCW, 5% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC.  All of our natural gas revenues are regulated by the PSCW.

Our ability to obtain rate adjustments in the future is dependent upon regulatory action and there can be no assurance that we will be able to obtain rate adjustments in the future that will allow us to recover our prudent costs and expenses and to maintain our current authorized rates of return.

Factors beyond We Power's control could adversely affect project costs and completion of the natural gas‐fired and coal‐fired generating units We Power is constructing as part of Wisconsin Energy's PTF strategy.

Under Wisconsin Energy's PTF strategy, we expect to meet a significant portion of our future generation needs through the leasing of two 545 MW natural gas‐fired generating units at PWGS and two 615 MW coal‐fired generating units to be located adjacent to our existing Oak Creek Power Plant.  PWGS 1 was placed in service in July 2005 and has a current dependable capability of 575 MW.  A second 545 MW natural gas‐fired generating unit is currently being constructed.

Large construction projects of this type are subject to usual construction risks over which We Power will have limited or no control and which might adversely affect project costs and completion time.  These risks include, but are not limited to, shortages of, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, the inability to obtain necessary permits in a timely manner and changes in applicable law or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, governmental actions and events in the global economy.

As required by the Energy Policy Act, FERC developed new rules to implement certain provisions of the Energy Policy Act.  Pursuant to these new rules, we requested FERC authorization in November 2006 to lease from We Power the three PTFunits that are currently being constructed by We Power.  We received authorization from FERC for these leases in December 2006.

We face significant costs of compliance with existing and future environmental regulations.

We are subject to extensive environmental regulations affecting our past, present and future operations relating to, among other things, air emissions such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates and mercury, water discharges, management of hazardous and solid waste (including polychlorinated biphenyls (PCBs)) and removal of degraded lead paint.  We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities.

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Existing environmental regulations may be revised or new laws or regulations may be adopted which could result in significant additional expenditures, operating restrictions on our facilities and increased compliance costs.  The operation of emission control equipment to meet emission limits and further regulations on our intake and discharge of water could increase our operating costs and could reduce the generating capacity of our power plants.  In the event we are not able to recover all of our environmental expenditures from our customers in the future, our results of operations could be adversely affected.

Our electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at our current and former facilities, as well as at third‐party owned sites.  Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.

In addition, we may also be responsible for liabilities associated with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities.  If we fail to comply with environmental laws and regulations or cause harm to the environment or persons, even if caused by factors beyond our control, that failure or harm may result in the assessment of civil or criminal penalties and damages against us.  The incurrence of a material environmental liability could have a significant adverse effect on our results of operations and financial condition.

Ownership and operation of nuclear generating units involve inherent risks that may result in substantial costs and liabilities.

We own two 518 MW nuclear electric generating units at Point Beach.  The units are operated by NMC, a joint venture of Wisconsin Energy and affiliates of other unaffiliated utilities.  During 2006, our nuclear generating units provided approximately 25.7% of our net electric energy supply.  In December 2006, we announced that we had reached a definitive agreement to sell our nuclear plant to an affiliate of FPL.  This transaction is subject to regulatory review and approval and we anticipate it will close during the third quarter of 2007.Until the transaction is approved, we continue to own Point Beach and retain exclusive rights to the energy generated by the plant, as well as financial responsibility for the safe operation, maintenance and decommissioning of Point Beach.

Our nuclear facilities are subject to environmental, health and financial risks, including: handling of nuclear materials, on‐site storage of spent nuclear fuel and the current lack of a long‐term solution for disposal of materials; mechanical or structural problems; lapses in maintenance procedures; human errors in the operation of the reactors or safety systems; limitations on the amounts and types of insurance coverage commercially available; the continued ability of NMC to effectively manage and operate our nuclear facilities; and uncertainties regarding our ability to maintain adequate reserves for decommissioning the units.  While we have no reason to anticipate a serious nuclear incident at our units, if an incident were to occur, it could result in substantial costs to us that may significantly exceed the amount of our insurance coverage and reserves.

The NRC has broad authority to impose licensing and safety related requirements for the operation of nuclear generating facilities.  In the event of non‐compliance, the NRC has the authority to impose fines or shut down a unit, or both, until compliance is achieved.  Further, in the event of a major incident at a nuclear facility anywhere in the world, the NRC could limit or prohibit the operation or licensing of any domestic nuclear unit.

As a result of the September 11, 2001 terrorist attacks, the NRC and the industry have been strengthening security at nuclear power plants.  Increased security measures and other safety requirements could require us to make substantial capital expenditures at our nuclear generating units.

Acts of terrorism could materially adversely affect our financial condition and results of operations.

Our electric generation and gas transportation facilities, including our nuclear facilities and the facilities of third parties on which we rely, could be targets of terrorist activities.  A terrorist attack on our facilities could result in a full or partial disruption of our ability to generate, transmit, transport or distribute electricity or natural gas or cause environmental repercussions.  Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially adversely affect our results of operations and financial condition.

---

Energy sales are impacted by seasonal factors and varying weather conditions from year‐to‐year.

Our electric and gas utility businesses are generally seasonal businesses.  Demand for electricity is greater in the summer and winter months associated with cooling and heating.  In addition, demand for natural gas peaks in the winter heating season.  As a result, our overall results in the future may fluctuate substantially on a seasonal basis.  In addition, we have historically had lower revenues and net income when weather conditions are milder.  Our rates in Wisconsin are set by the PSCW based on estimated temperatures that approximate 20‐year averages.  Mild temperatures during the summer cooling season and during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business.  In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.

Higher natural gas costs may negatively impact our electric and gas utility operations.

Significant increases in the cost of natural gas affect our electric and gas utility operations.  Natural gas costs have increased significantly because the supply of natural gas in recent years has not kept pace with the demand for natural gas, which has grown throughout the United States as a result of increased reliance on natural gas‐fired electric generating facilities.  We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas reserves are developed.

Our electric operations burn natural gas in several of our peaking power plants and in the leased PWGS 1 and as a supplemental fuel at several coal‐fired plants, and in many instances the cost of purchased power is tied to the cost of natural gas.  In addition, higher natural gas costs also can have the effect of increasing demand for other sources of fuel thereby increasing the costs of these fuels as well.

In addition, higher natural gas costs increase our working capital requirements.  As a result of our GCRM, our gas distribution business receives dollar for dollar pass through of the cost of natural gas.  However, increased natural gas costs increase the risk that customers will switch to alternative sources of fuel or reduce their usage, which could reduce future gas margins.  In addition, higher natural gas costs combined with slower economic conditions also exposes us to greater risks of accounts receivable write‐offs as more customers are unable to pay their bills.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our facilities.

We are dependent on coal for much of our electric generating capacity.  While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us.  The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us.  In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster.  If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to obtain additional MWh purchases through other potentially higher cost generating resources in the MISO Midwest Market.  Higher costs to obtain coal increase our working capital requirements.

Our financial performance may be adversely affected if we are unable to successfully operate our facilities.

Our financial performance depends on the successful operation of our electric generating and gas distribution facilities.  Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences.  Unplanned generation outages can result in additional maintenance expenses as well as incremental replacement power costs.

We are exposed to risks related to general economic conditions in our service territories.

Our electric and gas utility businesses are impacted by the economic cycles of the customers we serve.  In the event regional economic conditions decline, we may experience reduced demand for electricity or natural gas that could result in decreased earnings and cash flow.  In addition, regional economic conditions also impact our collections of accounts receivable.

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Our business is dependent on our ability to successfully access capital markets.

We rely on access to short‐term and long‐term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements.  We have historically secured funds from a variety of sources, including the issuance of short‐term and long‐term debt securities and preferred stock.  Successful implementation of our long‐term business strategies is dependent upon our ability to access the capital markets under competitive terms and rates.  If our access to the capital markets were limited due to a ratings downgrade, prevailing market conditions or other factors, our results of operations and financial condition could be materially adversely affected.

Governmental agencies could modify our permits, authorizations or licenses.

We are required to comply with the terms of various permits, authorizations and licenses.  These permits, authorizations and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued.  In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility.  Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.

Also, if we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other associated costs in our rates in a timely manner, our results of operations and financial condition could be materially adversely affected.

Restructuring in the regulated energy industry could have a negative impact on our business.

The regulated energy industry continues to experience significant structural changes.  Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us.  It is uncertain when retail access might be implemented in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations.  Under retail access legislation, customers are permitted to choose their own electric generation supplier.  All Michigan electric customers were able to choose their electric generation supplier beginning in January 2002.  Although competition and customer switching to alternative suppliers in our service territory in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.

FERC continues to support the existing RTOs that affect the structure of the wholesale market within those RTOs.  In connection with its status as a FERC approved RTO, MISO implemented the MISO Midwest Market on April 1, 2005.  The MISO Midwest Market rules require that all market participants submit day‐ahead and/or real‐time bids and offers for energy at locations across the MISO region.  MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a LMP that reflects the market price for energy.  As a participant in the MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system.

Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system.  MISO implemented the LMP system, a market‐based platform for valuing transmission congestion.  The LMP system includes the ability to mitigate or eliminate congestion charges through the use of FTRs.  FTRs are allocated to market participants by MISO for a twelve month period.  There can be no assurance that we will be granted an adequate level of FTRs in the future to avoid material unhedged congestion charges.  As allowed by the PSCW, unhedged congestion charges are deferred and we expect to recover these costs in future rates, subject to review and approval of the PSCW.





|ITEM 1B | UNRESOLVED STAFF COMMENTS
|------- | -------------------------

None.

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|ITEM 2. | PROPERTIES
|------- | ----------

We own our principal properties outright, except that the major portion of electric utility distribution lines, steam utility distribution mains and gas utility distribution mains and services are located, for the most part, on or in streets and highways and on land owned by others.

As of December 31, 2006, we owned or leased the following generating stations with dependable capabilities during 2006 as indicated.



|Name                                   |  | Fuel    |  | No. of
Generating
Units |  | Dependable
Capability
in MW (a)
July
|-------------------------------------- |  | ------- |  | ----------------------- |  | ------------------------------------
|                                       |  |         |  |                         |  |                                     
|Steam Plants                           |  |         |  |                         |  |                                     
|Point Beach                            |  | Nuclear |  | 2                       |  | 1,026                               
|Oak Creek                              |  | Coal    |  | 4                       |  | 1,135                               
|Presque Isle                           |  | Coal    |  | 9                       |  | 618                                 
|Pleasant Prairie                       |  | Coal    |  | 2                       |  | 1,224                               
|Valley                                 |  | Coal    |  | 2                       |  | 267                                 
|Edgewater 5 (b)                        |  | Coal    |  | 1                       |  | 105                                 
|Milwaukee County                       |  | Coal    |  | 3                       |  | 10                                  
|                                       |  |         |  |                         |  |                                     
|Total Steam Plants                     |  |         |  | 23                      |  | 4,385                               
|Hydro Plants (13 in number)            |  |         |  | 33                      |  | 54                                  
|Port Washington Generating Station (c) |  | Gas     |  | 1                       |  | 575                                 
|Germantown Combustion Turbines         |  | Gas/Oil |  | 5                       |  | 345                                 
|Concord Combustion Turbines            |  | Gas/Oil |  | 4                       |  | 388                                 
|Paris Combustion Turbines              |  | Gas/Oil |  | 4                       |  | 400                                 
|Other Combustion Turbines & Diesel     |  | Gas/Oil |  | 4                       |  | 38                                  
|                                       |  |         |  |                         |  |                                     
|Total System                           |  |         |  | 74                      |  | 6,185                               
|                                       |  |         |  |                         |  |                                     
|                                       |  |         |  |                         |  |                                     
|                                       |  |         |  |                         |  |                                     





|(a) | Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year.  We are a summer peaking electric utility.  The values were established by test and may change slightly from year to year.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                              
|(b) | We have a 25% interest in Edgewater 5 Generating Unit, which is operated by Alliant Energy Corp, an unaffiliated utility.                                                                                                                                                                    
|    |                                                                                                                                                                                                                                                                                              
|(c) | Effective July 2005, we began leasing PWGS 1, a natural gas‐fired generation unit with 575 MW of dependable capability, from We Power under a 25 year lease.                                                                                                                                 

We have a power purchase contract with an unaffiliated independent power producer.  The contract is for 236 MW of firm capacity from a gas‐fired cogeneration facility that expires in 2022.

As of December 31, 2006, our electric utility operated approximately 22,050 pole‐miles of overhead distribution lines and 22,440 miles of underground distribution cable, as well as approximately 387 distribution substations and 278,000 line transformers.  We own various office buildings and service centers throughout our service areas.

As of December 31, 2006, our gas distribution system included approximately 9,247 miles of distribution mains connected at 22 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian, Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company.  We have a liquefied natural gas storage plant that converts and stores in liquefied form natural gas received during periods of low consumption.  The liquefied natural gas storage plant has a send‐out capability of 70,000 Dth per day.  We also have a propane air system for peaking purposes.  This propane air system will provide approximately 2,000 Dth per day of supply to the system.  Our gas distribution system consists almost entirely of plastic and coated steel pipe.  We also own office buildings, gas regulating and metering stations and major service centers, including garage and warehouse facilities, in certain communities in which we serve.  Where distribution lines and services and gas distribution mains and services occupy private property, we have in some, but not all instances obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

---

As of December 31, 2006, the combined steam systems supplied by the Valley and Milwaukee County Power Plants consisted of approximately 43 miles of both high pressure and low pressure steam piping, 9 miles of walkable tunnels and other pressure regulating equipment.





|ITEM 3. | LEGAL PROCEEDINGS
|------- | -----------------



In addition to those legal proceedings discussed below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business.  Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.



ENVIRONMENTAL MATTERS

We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations.  Management believes that, perhaps with immaterial exceptions, our existing facilities are in compliance with applicable environmental requirements.

EPA Information Requests:   We responded to an EPA request for information pursuant to CERCLA Section 104(e) for the Solvay Coke and Gas Site located in Milwaukee, Wisconsin.  All potentially responsive records and corporate legal files have been reviewed and responsive information was provided in October 2004.  A predecessor company of ours owned a parcel of property that is within the property boundaries of the site.  In April 2006, we received a special notice letter from the EPA identifying us as a potentially responsible party and commencing a negotiation period with the EPA and other parties regarding the conduct of a RI/FS and reimbursement of the EPA's past costs.  We, along with other parties, have entered into an Administrative Settlement Agreement and Order with the EPA to perform the RI/FS and reimburse the EPA's oversight costs.  The parties anticipate that investigation activities will commence in 2007.  We do not admit to any liability for the site, waive any liability defenses, or commit to perform future site remedial activities at this time through the Settlement Agreement.  Our share of the costs to perform the RI/FS and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported in Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, Ash Landfill Sites and EPA ‐ Proposed Consent Decree in Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal‐ash landfills, manufactured gas plant sites and air quality.



UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Rates and Regulatory Matters and Power the Future in Item 7 for information concerning rate matters in the jurisdictions where we do business.



OTHER MATTERS

Used Nuclear Fuel Storage and Removal:   See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Nuclear Operations in Item 7 for information concerning the DOE's breach of contract with us that required the DOE to begin permanently removing used nuclear fuel from Point Beach by January 31, 1998.

Stray Voltage:   In recent years, several actions by dairy farmers have been commenced or claims made against us for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of our electrical system.

---

On February 26, 2004, a Wisconsin jury awarded $850,000 to a dairy farmer who alleged that our distribution system caused damages to his livestock.  We appealed this decision.  In April 2006, the Wisconsin Court of Appeals affirmed the jury's verdict against us.  We paid $1.3 million, including interest and costs, to the plaintiffs in this suit.

In May 2005, a stray voltage lawsuit was filed against us.  We do not believe the lawsuit has merit and we will vigorously defend the case.  The trial for this matter is scheduled to begin in April 2007.  This claim against us is not expected to have a material adverse effect on our financial condition or results of operations.

Even though any claims which may be made against us with respect to stray voltage and ground currents are not expected to have a material adverse effect on our financial condition, we continue to evaluate various options and strategies to mitigate this risk.  For additional information, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Legal Matters in Item 7.

Electromagnetic Fields:   Claims have been made or threatened against electric utilities across the country for bodily injury, disease or other damages allegedly caused or aggravated by exposure to electromagnetic fields associated with electric transmission and distribution lines.  Results of scientific studies conducted to date have not established the existence of a causal connection between electromagnetic fields and any adverse health effects.  We believe that our facilities are constructed and operated in accordance with applicable legal requirements and standards.  Currently, there are no cases pending or threatened against us with respect to damage caused by electromagnetic fields.

For information regarding additional legal matters, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Legal Matters in Item 7.





|ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
|------- | ---------------------------------------------------

No matters were submitted to a vote of our security holders during the fourth quarter of 2006.





EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages at December 31, 2006 and positions of our executive officers are listed below along with their business experience during the past five years.  All officers are appointed until they resign, die or are removed pursuant to the Bylaws.  There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.  Reference to Wisconsin Gas LLC includes the time spent with the company prior to its conversion from a corporation to an LLC.

Gale E. Klappa.  Age 56.

- Wisconsin Energy Corporation ‐ Chairman of the Board and Chief Executive Officer since May 2004.  President since April 2003.
- Wisconsin Electric Power Company ‐ Chairman of the Board since May 2004.  President and Chief Executive Officer since August 2003.
- Wisconsin Gas LLC ‐ Chairman of the Board since May 2004.  President and Chief Executive Officer since August 2003.
- The Southern Company ‐ Executive Vice President, Chief Financial Officer and Treasurer from March 2001 to April 2003.  Chief Strategic Officer from October 1999 to March 2001.  The Southern Company is a public utility holding company serving the southeastern United States.
- Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since 2003.

Charles R. Cole.  Age 60.

- Wisconsin Electric Power Company ‐ Senior Vice President since 2001.
- Wisconsin Gas LLC ‐ Senior Vice President since July 2004.

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Stephen P. Dickson.  Age 46.

- Wisconsin Energy Corporation ‐ Vice President since 2005.  Controller since 2000.
- Wisconsin Electric Power Company ‐ Vice President since 2005.  Controller since 2000.
- Wisconsin Gas LLC ‐ Vice President since 2005.  Controller since 1998.

James C. Fleming.  Age 61.

- Wisconsin Energy Corporation ‐ General Counsel since March 2006.  Executive Vice President since January 2006.
- Wisconsin Electric Power Company ‐ General Counsel since March 2006.  Executive Vice President since January 2006.
- Wisconsin Gas LLC ‐ General Counsel since March 2006.  Executive Vice President since January 2006.
- Southern Company Services, Inc. ‐ Vice President and Associate General Counsel from 1998 to December 2005.  Southern Company Services is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Frederick D. Kuester.  Age 56.

- Wisconsin Energy Corporation ‐ Executive Vice President since May 2004.
- Wisconsin Electric Power Company ‐ Executive Vice President since May 2004.  Chief Operating Officer since October 2003.
- Wisconsin Gas LLC ‐ Executive Vice President since May 2004.
- Mirant Corporation ‐ Senior Vice President ‐ International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia‐Pacific Limited from 1999 to October 2003.  Mirant is a multi‐national energy company that produces and sells electricity.  Mirant Corporation and certain of its subsidiaries voluntarily filed for bankruptcy in July 2003.  Other than certain Canadian subsidiaries, none of Mirant's international subsidiaries filed for bankruptcy.

Allen L. Leverett.  Age 40.

- Wisconsin Energy Corporation ‐ Executive Vice President since May 2004.  Chief Financial Officer since July 2003.
- Wisconsin Electric Power Company ‐ Executive Vice President since May 2004.  Chief Financial Officer since July 2003.
- Wisconsin Gas LLC ‐ Executive Vice President since May 2004.  Chief Financial Officer since July 2003.
- Georgia Power Company ‐ Executive Vice President, Chief Financial Officer and Treasurer from May 2002 to July 2003.  Assistant Treasurer from 2000 to 2002.  Georgia Power Company is a utility affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
- Southern Company Services, Inc. ‐ Vice President and Treasurer from 2000 to 2002.  Southern Company Services is also an affiliate of The Southern Company.

Kristine A. Rappé.  Age 50.

- Wisconsin Energy Corporation ‐ Senior Vice President and Chief Administrative Officer since May 2004.  Corporate Secretary from 2001 to August 2004.  Vice President from 2003 to April 2004.
- Wisconsin Electric Power Company ‐ Senior Vice President and Chief Administrative Officer since May 2004.  Corporate Secretary from 2001 to August 2004.  Vice President from 2001 to April 2004.
- Wisconsin Gas LLC ‐ Senior Vice President and Chief Administrative Officer since May 2004.  Corporate Secretary from 2001 to August 2004.  Vice President from 2001 to April 2004.

Larry Salustro.  Age 59.

- Wisconsin Energy Corporation ‐ Executive Vice President since May 2004.  General Counsel from 2000 to March 2006.  Senior Vice President from 2000 to April 2004.
- Wisconsin Electric Power Company ‐ Executive Vice President since May 2004.  General Counsel from 2000 to March 2006.  Senior Vice President from 2000 to April 2004.
- Wisconsin Gas LLC ‐ Executive Vice President since May 2004.  General Counsel from 2000 to March 2006.  Senior Vice President from 2000 to April 2004.

Certain executive officers also hold offices in Wisconsin Energy's non‐utility subsidiaries and our non‐utility subsidiary.

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PART II

|ITEM 5. | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|------- | ------------------------------------------------------------------------------------------------------------



DIVIDENDS AND COMMON STOCK PRICES

Dividends declared on our common stock during the two most recent fiscal years are set forth below.  Dividends were paid entirely in cash.  Dividends were paid to our sole common stockholder, Wisconsin Energy Corporation.  There is no established public trading market for our common stock.



|Quarter |  | 2006                  |  | 2005  
|------- |  | --------------------- |  | ------
|        |  |                       |  |       
|        |  | (Millions of Dollars)
|        |  |                       |  |       
|First   |  | $44.9                 |  | $44.9 
|Second  |  | 44.9                  |  | 44.9  
|Third   |  | ‐                     |  | 44.9  
|Fourth  |  | 89.8                  |  | 44.9  
|        |  |                       |  |       
|Total   |  | $179.6                |  | $179.6
|        |  |                       |  |       
|        |  |                       |  |       
|        |  |                       |  |       



Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, earnings, financial condition and other requirements.

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances.  Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.  For additional information regarding restrictions on our ability to pay dividends, see Note N ‐‐ Common Equity in the Notes to Consolidated Financial Statements in Item 8.

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|ITEM 6.  SELECTED FINANCIAL DATA                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|---------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------- | ------------- | -------------- | -------------- | --------------- | ------------------------- | --------------- | ---------------
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|WISCONSIN ELECTRIC POWER COMPANY                           |                                                                                                                     
|CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA       |                                                                                                                     
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|Financial                                                  |                                                                                                                      | 2006                                                                      |               | 2005           |                | 2004            |                           | 2003            |                
|Year Ended December 31                                     |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Earnings available for                                                                                               |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      | common stockholder (Millions)                                             |               | $        275.6 |                | $        283.6  |                           | $        248.7  |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Operating revenues (Millions)                                                                                        |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      | Electric                                                                  |               | $     2,499.5  |                | $     2,320.9   |                           | $     2,070.8   |                
|                                                           |                                                                                                                      | Gas                                                                       |               | 590.0          |                | 593.6           |                           | 523.8           |                
|                                                           |                                                                                                                      | Steam                                                                     |               | 27.2           |                | 23.5            |                           | 22.0            |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Total operating revenues                                                                                             |                                                                           | $     3,116.7 |                | $     2,938.0  |                 | $     2,616.6             |                 | $     2,521.9  
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|At December 31 (Millions)                                  |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Total assets                                                                                                         |                                                                           | $     8,257.8 |                | $     7,909.2  |                 | $     7,050.3             |                 | $     6,644.6  
|                                                           | Long-term debt and capital lease                                                                                     |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      | obligations (including current maturities)                                |               | $     2,152.1  |                | $     2,058.5   |                           | $     1,706.8   |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited) |                                                                                                                     
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 | (Millions of Dollars) (a) |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 | March                     |                 | June           
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|Three Months Ended                                         |                                                                                                                      |                                                                           |               | 2006           |                | 2005            |                           | 2006            |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Total operating revenues                                                                                             |                                                                           |               |                | $        872.7 |                 | $        759.7            |                 | $        685.8 
|                                                           | Operating income                                                                                                     |                                                                           |               |                | $        142.6 |                 | $        121.6            |                 | $          94.3
|                                                           | Earnings available for                                                                                               |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      | common stockholder                                                        |               |                |                | $          87.1 |                           | $          70.4 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 | September                 |                 | December       
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|Three Months Ended                                         |                                                                                                                      |                                                                           |               | 2006           |                | 2005            |                           | 2006            |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           | Total operating revenues                                                                                             |                                                                           |               |                | $        745.2 |                 | $        711.5            |                 | $        813.0 
|                                                           | Operating income                                                                                                     |                                                                           |               |                | $        126.1 |                 | $        130.2            |                 | $          92.9
|                                                           | Earnings available for                                                                                               |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      | common stockholder                                                        |               |                |                | $          77.7 |                           | $          78.9 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|                                                           |                                                                                                                      |                                                                           |               |                |                |                 |                           |                 |                
|(a)                                                        | Quarterly results of operations are not directly comparable because of seasonal and other factors.  See Management's |                                                                          
|                                                           |                                                                                                                      | Discussion and Analysis of Financial Condition and Results of Operations. |               |                |                |                 |                           |                



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|ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|------- | -------------------------------------------------------------------------------------



CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Electric Power Company, a wholly‐owned subsidiary of Wisconsin Energy, is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan.  Unless qualified by their context, when used in this document the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary.

Wisconsin Energy is also the parent company of Wisconsin Gas, a natural gas distribution utility which serves customers throughout Wisconsin, Edison Sault, an electric utility which serves customers in the Upper Peninsula of Michigan, and We Power.  We Power is principally engaged in the engineering, construction and development of electric generating power facilities for long‐term lease to us.  Wisconsin Electric and Wisconsin Gas have combined common functions and operate under the trade name of "We Energies".



CORPORATE STRATEGY

Business Opportunities

Wisconsin Energy's key corporate strategy is PTF, which was announced in September 2000.  This strategy is designed to address Wisconsin's growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel‐diverse, reasonably priced electric supply.  It is also designed to improve the delivery of energy within our distribution systems to meet increasing customer demands and to support our commitment to improved environmental performance.  Wisconsin Energy's PTF strategy, which is discussed further below, is having and is expected to continue to have a significant impact on us.  In July 2005, the first of four new electric generating units under the PTF strategy was placed into service.  Construction on the remaining three units is underway.

Proposed Sale of Point Beach:   In February 2006, we announced that we were undertaking a formal review regarding our options for the ownership and operation of Point Beach. These options included (1) continued operation by NMC, (2) having a third party other than NMC operate the plant, (3) a return to in‐house operations by us, (4) sale of the plant and (5) a partial sale of the plant with us retaining a minority interest in the Plant.  Under this fifth option, the new majority owner would operate the plant.  After a thorough review of the various options, we concluded that a full sale of the plant was in our best interest and in the best interest of our customers.

In December 2006, we announced that we had signed a definitive agreement with an affiliate of FPL to sell Point Beach for approximately $998 million, subject to closing price adjustments.  Under the terms of the sale, the buyer would assume the obligation to decommission the plant, and we would transfer assets in a qualified trust for decommissioning.  We would retain assets in a non‐qualified decommissioning trust.  We also entered into a long‐term power purchase agreement to purchase all of the existing capacity and energy of the plant.  This long‐term power purchase agreement will become effective upon the closing of the sale.  If and when the sale is completed (or earlier if an interim operating agreement with FPL is activated by us), NMC would transfer Point Beach's operating licenses to FPL and our relationship with NMC would be terminated.  The sale of the plant and the long‐term power purchase agreement are subject to review and approval by various regulatory agencies including the NRC, PSCW, MPSC and FERC.  We anticipate closing the sale during the third quarter of 2007.

We, along with FPL, have made a request to the IRS for a Private Letter Ruling (PLR) related to the transfer of the qualified decommissioning trust assets.  We are requesting permission to withdraw excess funds from the qualified trust without receiving unfavorable tax treatment.  If we receive a favorable PLR, we would use the excess funds for the direct benefit of our customers.  If we do not receive a favorable PLR, then the purchase price would be adjusted upward by approximately $50 million based on information as of December 31, 2006.  We are unable to predict how or even if the IRS may rule on our request for a PLR.

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If the sale is approved, we expect to receive after‐tax cash proceeds exceeding $1.0 billion from the sale and the liquidation of the decommissioning trust assets.  The net sales proceeds are expected to exceed our cost in the nuclear plant, and, absent regulatory treatment, we would expect to record a gain on the sale.  However, we have made a filing with PSCW to defer any gain (net of transaction related costs) as a regulatory liability that would be applied to the benefit of our customers in future rate proceedings.  As such, we do not expect the sale of the plant, if approved, to have a material impact on our 2007 earnings.

Power the Future Strategy:   In February 2001, Wisconsin Energy filed a petition with the PSCW that would allow Wisconsin Energy to begin implementing its 10‐year PTF strategy to improve the supply and reliability of electricity in Wisconsin.  PTF is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable.  Under PTF, Wisconsin Energy plans to add new coal‐fired and natural gas‐fired generating capacity to the state's power portfolio which would allow us to maintain approximately the same fuel mix as exists today.  PWGS 1 and 2 and OC 1 and 2 have a total output of 2,320 MW, of which Wisconsin Energy expects to own 2,120 MW.  As part of its PTF strategy, Wisconsin Energy plans to (1) invest approximately $2.6 billion in 2,120 MW of new natural gas‐fired and coal‐fired generating capacity at existing sites; (2) upgrade our existing electric generating facilities; and (3) invest in upgrades of our existing energy distribution system.  The new generating capacity will be built by We Power.

Subsequent to Wisconsin Energy's February 2001 filing, the state legislature amended several laws, making changes which were critical to the implementation of PTF.  In October 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed with PTF and for Wisconsin Energy to incur the associated pre‐certification expenses.  However, individual expenses are subject to review by the PSCW in order to be recovered.

In November 2001, Wisconsin Energy created We Power to design, construct, own and lease the new generating capacity.  We will lease each new generating facility from We Power as well as operate and maintain the new plants under 25‐ to 30‐year lease agreements approved by the PSCW.  Based upon the structure of the leases, Wisconsin Energy expects to recover the investments in We Power's new facilities over the initial lease term.  At the end of the leases, we will have the right to acquire the plants outright at market value or to renew the leases.  We expect that payments under the plant leases will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.

Under the PTF strategy, Wisconsin Energy expects to meet a significant portion of our future generation needs through We Power's construction of the PWGS units and the Oak Creek expansion.

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As of December 31, 2006, Wisconsin Energy:



| | Received approval from the PSCW to build two 545 MW natural gas‐fired intermediate load units in Port Washington, Wisconsin (PWGS 1 and PWGS 2).  PWGS 1 was placed into service in July 2005 and is fully operational.  PWGS 1 was completed within the PSCW approved cost parameters.                                                                                                                                                                                                
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | Completed site preparation for PWGS 2 in early 2006, and procured all of the major components for PWGS 2.  Construction is underway and PWGS 2 is expected to be operational in 2008.                                                                                                                                                                                                                                                                                                  
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | Received approval from the PSCW to build two 615 MW coal‐fired base load units (OC 1 and OC 2) adjacent to the site of our existing Oak Creek Power Plant in Oak Creek, Wisconsin (the Oak Creek expansion), with OC 1 expected to be in service in 2009 and OC 2 in 2010.  The CPCN was granted contingent upon us obtaining the necessary environmental permits.  We have received all permits necessary to commence construction.  In June 2005, construction commenced at the site.
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | Completed the planned sale of approximately a 17% ownership interest in the Oak Creek expansion to two co‐owners in November 2005.  We will lease We Power's approximate 515 MW interest in each unit.                                                                                                                                                                                                                                                                                 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | Received approval from the PSCW for various leases between us and We Power.                                                                                                                                                                                                                                                                                                                                                                                                            



Primary risks under PTF are construction risks associated with the schedule and costs for both Wisconsin Energy's Oak Creek expansion and PWGS 2, continuing legal challenges to permits obtained and changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, obtaining the investment capital from outside sources necessary to implement the strategy, governmental actions, and events in the global economy.

You can find additional information regarding risks associated with the PTF strategy, as well as the regulatory process, and specific regulatory approvals, in Factors Affecting Results, Liquidity and Capital Resources below.

Utility Operations:   We are realizing operating efficiencies through the integration of our operations with those of Wisconsin Gas.  These operating efficiencies are expected to increase customer satisfaction and reduce operating costs.  In connection with Wisconsin Energy's PTF strategy, we are improving our existing energy distribution systems and upgrading existing electric generating assets.

Divestiture of Assets

During 2000, we agreed to join ATC by transferring our electric utility transmission system assets to ATC in exchange for an ownership interest in this new company.  Transfer of these electric transmission assets became effective on January 1, 2001.  As of December 31, 2006, we had an ownership interest of approximately 25.8% in ATC.



RESULTS OF OPERATIONS

EARNINGS

2006 vs. 2005:   Earnings decreased to $275.6 million in 2006 compared with $283.6 million in 2005.  Operating income decreased $21.4 million between the comparative periods.  During 2006, we experienced mild weather, which reduced electric and gas sales.  In addition, operation and maintenance expenses increased due to the timing of scheduled outages and maintenance projects at our coal units.  However, these items were largely offset by improved recovery of fuel costs, only one scheduled refueling outage at Point Beach and increased gas margins.

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2005 vs. 2004:

The following table summarizes our consolidated earnings during 2006, 2005 and 2004.



|                                               |  | 2006                  |  | 2005     |  | 2004    
|---------------------------------------------- |  | --------------------- |  | -------- |  | --------
|                                               |  |                       |  |          |  |         
|                                               |  | (Millions of Dollars)
|Utility Gross Margin                           |  |                       |  |          |  |         
|Electric (See below)                           |  | $1,710.1              |  | $1,555.0 |  | $1,492.2
|Gas (See below)                                |  | 158.4                 |  | 147.3    |  | 146.9   
|Steam                                          |  | 18.6                  |  | 15.6     |  | 15.2    
|                                               |  |                       |  |          |  |         
|Total Gross Margin                             |  | 1,887.1               |  | 1,717.9  |  | 1,654.3 
|Other Operating Expenses                       |  |                       |  |          |  |         
|Other operation and maintenance                |  | 1,074.5               |  | 880.5    |  | 844.7   
|Depreciation, decommissioning and amortization |  | 270.9                 |  | 281.8    |  | 274.1   
|Property and revenue taxes                     |  | 85.8                  |  | 78.3     |  | 76.3    
|                                               |  |                       |  |          |  |         
|Operating Income                               |  | 455.9                 |  | 477.3    |  | 459.2   
|Equity in Earnings of Transmission Affiliate   |  | 33.9                  |  | 30.4     |  | 26.4    
|Other Income, net                              |  | 42.9                  |  | 28.4     |  | 7.1     
|Interest Expense                               |  | 87.0                  |  | 85.8     |  | 89.6    
|                                               |  |                       |  |          |  |         
|Income Before Income Taxes                     |  | 445.7                 |  | 450.3    |  | 403.1   
|Income Taxes                                   |  | 168.9                 |  | 165.5    |  | 153.2   
|Preferred Stock Dividend Requirement           |  | 1.2                   |  | 1.2      |  | 1.2     
|                                               |  |                       |  |          |  |         
|Earnings Available for Common Stockholder      |  | $275.6                |  | $283.6   |  | $248.7  
|                                               |  |                       |  |          |  |         
|                                               |  |                       |  |          |  |         
|                                               |  |                       |  |          |  |         

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Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2006 with similar information for 2005 and 2004, including a summary of electric operating revenues and electric sales by customer class.



|                                  |  | Electric Revenues and Gross Margin |  | Electric MWh Sales             
|--------------------------------- |  | ---------------------------------- |  | -------------------------------
|                                  |  |                                    |  |                                
|Electric Utility Operations       |  | 2006                               |  | 2005                           
|                                  |  |                                    |  |                                
|                                  |  | (Millions of Dollars)              |  | (Thousands, Except Degree Days)
|Customer Class                    |  |                                    |  |                                
|Residential                       |  | $870.8                             |  | $815.5                         
|Small Commercial/Industrial       |  | 796.0                              |  | 727.6                          
|Large Commercial/Industrial       |  | 637.0                              |  | 592.7                          
|Other‐Retail/Municipal            |  | 87.0                               |  | 103.1                          
|Resale‐Utilities                  |  | 73.5                               |  | 42.5                           
|Other Operating Revenues          |  | 35.2                               |  | 39.5                           
|                                  |  |                                    |  |                                
|Total Electric Operating Revenues |  | 2,499.5                            |  | 2,320.9                        
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|Fuel and Purchased Power          |  |                                    |  |                                
|Fuel                              |  | 487.7                              |  | 432.6                          
|Purchased Power                   |  | 301.7                              |  | 333.3                          
|                                  |  |                                    |  |                                
|Total Fuel and Purchased Power    |  | 789.4                              |  | 765.9                          
|                                  |  |                                    |  |                                
|Total Electric Gross Margin       |  | $1,710.1                           |  | $1,555.0                       
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|                                  |  |                                    |  |                                
|Weather ‐‐ Degree Days (a)        |  |                                    |  |                                
|Heating (6,663 Normal)            |  |                                    |  |                                
|Cooling (716 Normal)              |  |                                    |  |                                



|(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin.  Normal degree days are based upon a 20‐year moving average.
|---------------------------------------------------------------------------------------------------------------------------------------



Electric Utility Revenues and Sales

2006 vs. 2005:   Our electric utility operating revenues increased by $178.6 million, or 7.7%, when compared to 2005.  We estimate that revenues in 2006 were $213.3 million higher than 2005 due to pricing increases that we received in January 2006 and during 2005.  The most significant pricing increases authorized by the PSCW related to the recovery of higher fuel costs, costs associated with the new plants under Wisconsin Energy's PTF strategy and increased transmission costs.

Our electric utility operating revenues are expected to increase in 2007 primarily due to the impact of a full year of the January 2006 Wisconsin retail pricing increase and the expected implementation of increased wholesale rates, as well as the impacts of our fuel adjustment clause that are tied to our fuel and purchase power costs.  During 2006, we reserved approximately $38 million of revenues associated with favorable recoveries of fuel and purchased power.  For more information on the pricing increases and the fuel cost adjustment clause, see Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources.

Our electric sales volumes decreased by 1.7% in 2006 as compared to 2005 due to mild weather and lower commercial and industrial sales, offset by an increase in sales for resale.  Residential sales volumes decreased 2.8% due largely to weather.  In 2006, heating degree days decreased approximately 8.8% compared to 2005, and cooling degree days decreased approximately 23.8%.  We estimate that the weather had an unfavorable impact on operating revenues of approximately $46.5 million when compared to the prior year.  Total sales volumes to commercial/industrial customers decreased 2.8% between the comparative periods.  Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, decreased 1.4%.  Sales volumes in the Other Retail/Municipal class decreased approximately 19.6% compared to the prior year due, in part, to the expiration of a wholesale contract on December 31, 2005.  The increase in sales volumes to other utilities is attributed to the availability of PWGS 1 for all of 2006, which provided additional generation capacity.  PWGS 1

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2005 vs. 2004:   During 2005, our total electric utility operating revenues increased by $250.1 million or 12.1% when compared with 2004 primarily due to favorable weather during the summer of 2005 and pricing increases.

During 2005, we estimate that pricing increases contributed an additional $145.8 million of revenues than in 2004.  The most significant impact to rates was a March 2005 interim order we received from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power.  In November 2005, we received the final rate order, which authorized an additional $7.7 million of annual revenues.  Additional orders impacting rates in 2005 were the May 2004 and May 2005 orders we received from the PSCW authorizing annualized increases in electric rates of approximately $59.0 million and $59.7 million, respectively, primarily to cover construction costs associated with Wisconsin Energy's PTF strategy.

Total electric sales increased by 2.6% between 2005 and 2004.  Residential sales volumes increased 6.4% due to the favorable summer weather in 2005.  Total sales volumes to commercial/industrial customers increased 1.8% between comparative periods.  Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 2.4% due to the favorable weather during the summer of 2005.  We estimate that weather increased our electric revenues by approximately $68.8 million during 2005 as compared to the prior year.  As measured by cooling degree days, 2005 was 114.7% warmer than in 2004.

Sales volumes in the Resale‐Utilities class decreased 34.7% primarily due to the reduced availability of base‐load capacity for sale at competitive prices as a result of limited fuel supplies and outages.  Sales volumes to municipal utilities, the Other Retail/Municipal customer class, increased 14.3% between the periods due to higher off‐peak demand from lower margin municipal wholesale power customers.

Electric Fuel and Purchased Power Expenses

2006 vs. 2005:   Our fuel and purchased power expenses increased by $23.5 million, or approximately 3.1%, when compared to 2005.  Our average cost of fuel and purchased power increased from $23.95 per MWh in 2005 to $25.10 per MWh in 2006.  The largest factor for the higher cost per MWh was a 24.1% increase in the per MWh cost of coal‐fired generation, which includes coal and related transportation costs, between the comparative periods.  This increase was partially offset by increased generation from Point Beach and a decrease in the average costs of purchased power and fuel for our natural gas‐fired units.

Our electric fuel and purchased power expenses in 2007 are expected to be impacted by the duration of the scheduled nuclear refueling outage in the first quarter of 2007; the timing and completion of the proposed sale of Point Beach; the price of purchased power; the increased cost of coal and related transportation; and changes in electric sales.

2005 vs. 2004:   Gross fuel and purchased power costs for our electric utility increased by a total of $260.1 million during 2005 when compared with 2004.  During 2005, we deferred $72.8 million of fuel and purchased power costs which resulted in a net increase of fuel and purchased power expense of $187.3 million or 32.4% during 2005 when compared to 2004.  The increase in fuel and purchased power expense was driven by a 2.6% increase in MWh sales and an increase in our average cost of fuel and purchased power from $18.57 per MWh in 2004 to $23.95 per MWh in 2005, or 29.0% between the comparative periods.

The increase in our average cost of fuel and purchased power was due primarily to (1) the reduced availability of nuclear generation due to scheduled refueling outages, (2) higher natural gas prices that increased the cost of power supplied by natural gas, (3) the impact of the implementation of the MISO Midwest Market in April 2005 and (4) limitations on coal supplies due to transportation shortfalls.

During 2005, we had two scheduled refueling outages at our nuclear plant and in 2004 we had one scheduled refueling outage.  As a result, we had approximately 1,145,000 fewer MWh of nuclear generation in 2005.  Our average fuel cost for nuclear generation is approximately $5 per MWh, while the average energy cost for purchased power was approximately $55 per MWh.  We estimate that the reduction in nuclear generation resulted in approximately $57 million of increased fuel and purchased power costs in 2005 as compared to 2004.  During the

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In 2005, we experienced significant increases in the cost of natural gas used in our own generating assets and in the price of purchased energy which is highly influenced by the price of natural gas.  This increase was most significant in the last six months of 2005 due to market related factors including the hurricanes in the Gulf of Mexico.  The average combined cost per MWh of purchased energy and natural gas fired units in 2005 was 46.8% higher than in 2004, increasing total cost by approximately $72.5 million.

In April 2005, we began participating in the MISO Midwest Market which fundamentally changed the way we dispatch our generating units and obtain purchased energy.  As part of this new market, we are subject to new types of charges which, among other things, recognize the cost of transmission congestion, MWh losses and other costs associated with operating the generating units in an uneconomic fashion to support the MISO Midwest Market service territory.  The State of Wisconsin has a constrained transmission system and we believe these constraints result in higher costs for us than in other parts of the MISO Midwest Market service territory.  The incremental costs associated with the MISO Midwest Market charges identified above were approximately $28 million in 2005.  For more information regarding MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Industry Restructuring and Competition ‐‐ Electric Transmission and Energy Markets.

Our 2005 operations were also adversely impacted by limitations on deliveries of coal supply due to the failure of our primary rail delivery supplier to deliver contracted quantities of coal to our units.  The largest limitation was related to critical rail track maintenance in the Powder River basin.  This, in turn, resulted in reduced coal deliveries of the coal which primarily serves our Oak Creek and Pleasant Prairie generating units from June through December 2005.  In response to the reduced deliveries, we reduced generating output of these units during off‐peak periods when replacement power prices were lower, purchased more expensive replacement power and took measures to purchase and transport higher cost coal in place of contracted supplies when it made economic sense to do so.  We estimate that this increased our costs by approximately $52 million in 2005.  For additional information on the decreased coal deliveries, see Factors Affecting Results, Liquidity and Capital Resources ‐‐ Market Risks and Other Significant Risks ‐‐ Commodity Prices.

Under the State of Wisconsin fuel rules, we are allowed to request recovery in fuel revenues if our projected fuel and purchased power costs exceed bands established by the PSCW.  In March 2005, we received a rate order that allowed us to increase our annual revenues by $114.9 million (final order received in November 2005 for an annual increase of $122.6 million) due to increased fuel and purchased power costs.  As provided under the Wisconsin rules, we are also allowed to request deferral for the costs associated with adverse events which materially impact fuel and purchased power costs which were not anticipated, or for which costs could not be reasonably estimated at the time of the fuel recovery request for consideration in future rate proceedings.  During 2005, we deferred approximately $72.8 million of fuel and purchased power costs due to the extended outage at Point Beach Unit 2, the coal delivery problems and increased costs associated with the MISO Midwest Market.  During 2005, we estimate that we under‐recovered fuel and purchased power costs by $108.4 million before these deferred items.  Adjusted for the allowed deferrals, our net under‐recovered fuel and purchased power costs were approximately $35.6 million.

Gas Utility Revenues, Gross Margin and Therm Deliveries

The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2006, 2005 and 2004.



|Gas Utility Operations |  | 2006                  |  | 2005   |  | 2004  
|---------------------- |  | --------------------- |  | ------ |  | ------
|                       |  |                       |  |        |  |       
|                       |  | (Millions of Dollars)
|                       |  |                       |  |        |  |       
|Operating Revenues     |  | $590.0                |  | $593.6 |  | $523.8
|Cost of Gas Sold       |  | 431.6                 |  | 446.3  |  | 376.9 
|                       |  |                       |  |        |  |       
|Gross Margin           |  | $158.4                |  | $147.3 |  | $146.9
|                       |  |                       |  |        |  |       
|                       |  |                       |  |        |  |       
|                       |  |                       |  |        |  |       

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We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under our GCRM.  The following table compares our gas utility gross margin and therm deliveries by customer class during 2006, 2005 and 2004.



|                           |  | Gross Margin          |  | Therm Deliveries              
|-------------------------- |  | --------------------- |  | ------------------------------
|                           |  |                       |  |                               
|Gas Utility Operations     |  | 2006                  |  | 2005                          
|                           |  |                       |  |                               
|                           |  | (Millions of Dollars) |  | (Millions, Except Degree Days)
|Customer Class             |  |                       |  |                               
|Residential                |  | $104.8                |  | $96.4                         
|Commercial/Industrial      |  | 35.5                  |  | 33.0                          
|Interruptible              |  | 0.6                   |  | 0.5                           
|                           |  |                       |  |                               
|Total Gas Sold             |  | 140.9                 |  | 129.9                         
|Transported Gas            |  | 15.4                  |  | 15.6                          
|Other Operating            |  | 2.1                   |  | 1.8                           
|                           |  |                       |  |                               
|Total                      |  | $158.4                |  | $147.3                        
|                           |  |                       |  |                               
|                           |  |                       |  |                               
|                           |  |                       |  |                               
|                           |  |                       |  |                               
|Weather ‐‐ Degree Days (a) |  |                       |  |                               
|Heating (6,663 Normal)     |  |                       |  |                               



|(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin.  Normal degree days are based upon a 20‐year moving average.
|---------------------------------------------------------------------------------------------------------------------------------------

2006 vs. 2005:

The pricing increase was partially offset by a decline in gas sales volumes that was driven by mild winter weather and by lower customer usage.  Temperatures (as measured by heating degree days) were approximately 8.8% warmer in 2006 as compared to 2005.  The mild winter weather reduced customer demand for heating.  We estimate that the weather decreased our gross margin by approximately $8.3 million between the comparative periods.  We continue to see a reduction in normalized use of gas per customer which we believe is caused by high natural gas prices and the continued improvements in energy efficient appliances.  During 2006, we estimate this reduction in normalized use decreased our gross margin by approximately $2.0 million.  The decrease in volume of transport gas sales was due in part to fuel switching during months where gas commodity prices were high during 2006.  Residential therm deliveries decreased 8.0% as compared to 2005, due to warmer weather and a decrease in use per customer that was driven in part by high commodity prices.

Our gas utility's gross margin is expected to increase in 2007 primarily due to the impact of a full year of the January 2006 pricing increase.  In addition, 2007 gross margins will be impacted by weather and customer demand.  For more information on the pricing increases, see Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources.

2005 vs. 2004:Gas utility gross margin was relatively flat in 2005, increasing by only $0.4 million or 0.3%.  Total therm deliveries were 8.1% higher during 2005, primarily due to increased transport gas deliveries of 69.8 million therms.  Transport volumes increased between the comparative periods due to a higher amount of electric generation from natural gas within our service territory.  Our margins on transport gas volumes are significantly lower than our margins for retail gas sales, which is the primary reason why gross margin remained flat even with an increase in therm deliveries.

Other Operation and Maintenance Expenses

2006 vs. 2005:

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Our operation and maintenance expenses are expected to increase in 2007 as a result of increased amortizations related to the impact of the 2006 pricing increase.  In addition, operation and maintenance expenses are influenced by wage inflation, employee benefit costs and the length of plant outages.

2005 vs. 2004:   Other operation and maintenance expenses increased by $35.8 million or 4.2% during 2005 compared with 2004.  The most significant changes in our operation and maintenance expense related to increased lease costs and increased nuclear outage costs.  Partially offsetting these increases was a charge in 2004 for severance costs related to the voluntary severance program and lower employee costs in 2005 due to fewer employees.

The largest operations and maintenance increase was due to $50.0 million of additional costs related to lease agreements between us and We Power in connection with the PTF strategy.

In addition to the increased lease costs, our nuclear operating and maintenance expense increased approximately $11.0 million due to two scheduled refueling outages in 2005 where we also replaced the reactor vessel heads.  In 2004, we had one scheduled refueling outage.  This increase was partially offset by a $10.0 million settlement we received to resolve a vendor dispute.

Additionally, in 2004 we recognized $22.3 million of severance related costs due to the voluntary severance program that was implemented in the second half of 2004.  In 2005, we had approximately 138 fewer employees, which reduced operation and maintenance costs by $11.1 million.

Benefit costs increased $12.2 million between the comparative periods due to increased pension and medical costs.  In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post‐retirement medical and drug plans.

Depreciation, Decommissioning and Amortization Expense

2006 vs. 2005:   Depreciation, decommissioning and amortization expenses decreased by $10.9 million or 3.9% when compared to 2005.  In January 2006, we implemented new depreciation rates approved by the PSCW which reduced annual depreciation expenses.  We estimate that the new rates reduced annual depreciation expense by approximately $15 million, which was offset, in part, by net plant additions in 2006.  We expect depreciation, decommissioning and amortization expenses in 2007 to increase as a result of an overall increase in plant assets in service.

2005 vs. 2004:   Depreciation, decommissioning and amortization expense increased by $7.7 million in 2005 as compared to 2004.  This increase was primarily due to increased depreciable plant balances.

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Other Income, net

The following table identifies the components of consolidated other income, net during 2006, 2005 and 2004.



|Other Income, net           |  | 2006                  |  | 2005  |  | 2004 
|--------------------------- |  | --------------------- |  | ----- |  | -----
|                            |  |                       |  |       |  |      
|                            |  | (Millions of Dollars)
|                            |  |                       |  |       |  |      
|Capitalized Carrying Costs  |  | $25.0                 |  | $20.4 |  | $12.7
|AFUDC‐Equity                |  | 14.5                  |  | 9.2   |  | 1.7  
|Donations and Contributions |  | (6.0)                 |  | (6.7) |  | (5.6)
|Gross Receipts Tax Recovery |  | 4.0                   |  | 2.6   |  | 1.5  
|Other, net                  |  | 5.4                   |  | 2.9   |  | (3.2)
|                            |  |                       |  |       |  |      
|Total Other Income, net     |  | $42.9                 |  | $28.4 |  | $7.1 
|                            |  |                       |  |       |  |      
|                            |  |                       |  |       |  |      
|                            |  |                       |  |       |  |      

2006 vs. 2005:   Other income, net increased by $14.5 million when compared to 2005.  The largest increases relate to increased AFUDC ‐ Equity of $5.3 million and capitalized carrying costs of $4.6 million.  In 2007, we expect a reduction in AFUDC ‐ Equity as we placed in service the new scrubber at our Pleasant Prairie Power Plant in the fourth quarter of 2006.  The scrubber was installed as part of our EPA consent decree spending.  For further information on the consent decree with the EPA, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements.

2005 vs. 2004:   Other income, net increased by $21.3 million in 2005 compared to 2004.  Significant items included an increase of $7.7 million in the recognition of capitalized carrying costs, and a $7.5 million increase in AFUDC ‐ Equity due to a higher average balance of AFUDC qualifying utility construction projects in 2005.

Interest Expense

2006 vs. 2005:   Interest expense increased by $1.2 million in 2006 when compared with 2005.  This increase was due to higher interest rates on short‐term debt, increased average balances of commercial paper outstanding and a net increase in long‐term debt outstanding.  These increases were partially offset by the items that follow.  We expensed approximately $6.2 million in 2005 related to the amortization of costs associated with prior debt redemptions.  These costs were fully amortized as of July 2005; therefore, there was no similar expense in 2006.  In addition, there was increased capitalized interest in 2006 due to a higher average balance of construction projects in 2006.

We expect total interest expense in 2007 to increase reflecting a full year of interest on the $300 million of 5.70% Debentures that we issued in November 2006.

2005 vs. 2004:   Total interest expense decreased by $3.8 million in 2005 compared with 2004.  The major components of this decrease included a reduction in the amortization of debt premiums and increased capitalized interest in 2005 due to a higher average balance of construction projects in 2005.  These items were partially offset by increases in interest expense due mainly to higher interest rates on our short‐term debt.  Additionally, in November 2004 we sold $250 million of unsecured 3.50% Debentures due December 1, 2007, the proceeds of which were used to repay outstanding commercial paper, including commercial paper which funded the August 2004 retirement of our $140 million of 7‐1/4% First Mortgage Bonds.

Income Taxes

2006 vs. 2005:   Our effective income tax rate was 38.0% in 2006 compared with 36.9% in 2005.

2005 vs. 2004:   Our effective income tax rate was 36.9 % in 2005 compared with 38.0% in 2004.  This decrease in the effective income tax rate reflected higher AFUDC ‐ Equity.

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LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2006, 2005 and 2004:



|Wisconsin Electric         |  | 2006                  |  | 2005     |  | 2004    
|-------------------------- |  | --------------------- |  | -------- |  | --------
|                           |  |                       |  |          |  |         
|                           |  | (Millions of Dollars)
|Cash Provided by (Used in) |  |                       |  |          |  |         
|Operating Activities       |  | $498.5                |  | $481.3   |  | $630.8  
|Investing Activities       |  | ($473.8)              |  | ($482.1) |  | ($423.9)
|Financing Activities       |  | ($29.7)               |  | ($2.1)   |  | ($200.8)



Operating Activities

Cash provided by operating activities for 2006 totaled $498.5 million, which is a $17.2 million improvement over 2005.  There were two primary areas that drove this improvement in operating cash flows.  During 2006, we estimate that our collections of fuel costs improved by nearly $95 million as we had favorable collections in 2006 and unfavorable recoveries and fuel cost deferrals in 2005.  The other primary area related to the working capital requirements related to gas in storage.  During 2006, we entered into certain contracts that reduced our need to inject gas in storage.  In addition, lower gas commodity prices, offset in part by less withdrawals due to weather, have lowered working capital requirements between the comparative periods.  We estimate that these items reduced our cash needs for gas in storage by approximately $25.0 million.  Partially offsetting these items was an increase of cash taxes of approximately $58.6 million due to higher taxable earnings.

Cash provided by operating activities decreased to $481.3 million during 2005 compared with $630.8 million during 2004.  This decline reflected increased working capital needs, an increase in deferred costs, and an increase in cash taxes paid.  During 2005, we experienced significant increases in natural gas costs which increased our working capital requirements for natural gas in storage.  The increased natural gas costs also led to an increase in accounts receivable as the cost of gas is recovered dollar for dollar in our natural gas revenues.  During 2005, we also experienced increased deferred costs related to transmission costs and deferred fuel.



Investing Activities

During 2006, net cash outflows from investing activities were $473.8 million compared with $482.1 million in 2005.  The decrease primarily reflects lower capital expenditures of $10.5 million, partially offset by an increase in capital contributions to ATC of $3.6 million.

During 2005, we made net investments totaling $482.1 million compared to $423.9 during 2004.  Capital expenditures increased by $50.3 million to $409.2 million and were primarily related to facilitating compliance with the consent decree entered into with the EPA (See Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements).  In addition, expenditures associated with nuclear fuel purchases were higher by $19.7 million during 2005.  These increases were partially offset by a reduction in capital contributions to ATC of $14.0 million during 2005.

In 2007, if we are able to close on the sale of Point Beach, we expect to receive an additional $1 billion of after‐tax cash proceeds.

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Financing Activities

The following table summarizes our cash flows from financing activities:



|                                           |  | 2006                  |  | 2005     |  | 2004    
|------------------------------------------ |  | --------------------- |  | -------- |  | --------
|                                           |  |                       |  |          |  |         
|                                           |  | (Millions of Dollars)
|                                           |  |                       |  |          |  |         
|Dividends to Wisconsin Energy              |  | ($179.6)              |  | ($179.6) |  | ($179.6)
|Capital Contribution from Wisconsin Energy |  | 100.0                 |  | ‐        |  | ‐       
|Increase (Reduction) in Total Debt         |  | 50.0                  |  | 178.7    |  | (19.5)  
|Other                                      |  | (0.1)                 |  | (1.2)    |  | (1.7)   
|                                           |  |                       |  |          |  |         
|Cash Used in Financing                     |  | ($29.7)               |  | ($2.1)   |  | ($200.8)
|                                           |  |                       |  |          |  |         
|                                           |  |                       |  |          |  |         
|                                           |  |                       |  |          |  |         

During 2006, we used $29.7 million for net financing activities compared with $2.1 million during 2005.  In November 2006, we issued $300 million of 5.70% Debentures due December 1, 2036.  The net proceeds from the sale were used to retire our $200 million of 6‐5/8% Debentures due November 15, 2006 at their scheduled maturity and to repay outstanding commercial paper incurred for working capital requirements.  During 2006, short‐term debt decreased approximately $48.5 million.

In November 2004, we issued $250 million of unsecured 3.50% debentures due December 1, 2007, the proceeds of which were used to pay down outstanding commercial paper.  In August 2004, we retired $140 million of 7‐1/4% First Mortgage Bonds at their scheduled maturity.

For additional information concerning changes in our long‐term debt, see Note G ‐‐ Long‐Term Debt in the Notes to Consolidated Financial Statements.



CAPITAL RESOURCES AND REQUIREMENTS

In December 2006, we announced that we had reached an agreement to sell Point Beach to an affiliate of FPL.  If the sale is completed, we expect to receive over $1 billion of after‐tax cash proceeds from the sale and liquidation of decommissioning trust assets.  In the short‐term, these proceeds would be used to reduce outstanding debt or temporarily invested in short‐term securities.  However, as discussed in Corporate Developments ‐ Corporate Strategy, we have filed an application with the PSCW that outlines our intention to use the gain (net of transaction related costs) on the sale for the benefit of our customers as decided by our regulators in future rate proceedings.  As such, if the Point Beach sale is approved, we believe that the cash proceeds, after transaction costs and return of invested capital that will result from the sale will replace revenues that we would have received in future rate proceedings.



Capital Resources

We anticipate meeting our capital requirements during 2007 and the next several years primarily through internally generated funds and short‐term borrowings, supplemented from time to time, depending on market conditions and other factors, by the issuance of intermediate or long‐term debt securities and equity contributions from our parent.

We have access to capital markets and have been able to generate funds internally and externally to meet our capital requirements.  Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan.  We believe that we have adequate capacity to fund our operations for the foreseeable future through our borrowing arrangements and internally generated cash.

In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment.  We evaluated the possible issuance of environmental trust bonds for some time.  However, after extensive evaluation and analysis, we will not be pursuing an issuance of environmental trust bonds.

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We have a credit agreement that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of December 31, 2006, we had approximately $485.9 million of available unused lines under our bank back‐up credit facility and $304.2 million of total consolidated short‐term debt outstanding.

We review our bank back‐up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations.  The following table summarizes our facility at December 31, 2006:



|Total Facility        |  | Letters
of Credit |  | Credit Available |  | Facility
Expiration |  | Facility
Term
|--------------------- |  | ----------------- |  | ---------------- |  | ------------------- |  | -------------
|                      |  |                   |  |                  |  |                     |  |              
|(Millions of Dollars) |  |                   |  |                 
|                      |  |                   |  |                  |  |                     |  |              
|$500.0                |  | $14.1             |  | $485.9           |  | March 2011          |  | 5 year       

On March 30, 2006, we entered into an unsecured five year $500 million bank back‐up credit facility to replace a $250 million three year credit facility with an expiration date of June 2007 and a $125 million three year credit facility with an expiration date of November 2007.  This new facility will expire in March 2011.  This facility has a renewal provision for two one‐year extensions, subject to lender approval.

The following table shows our consolidated capitalization structure at December 31:



|Capitalization Structure        |  | 2006                  |  | 2005  
|------------------------------- |  | --------------------- |  | ------
|                                |  |                       |  |       
|                                |  | (Millions of Dollars)
|                                |  |                       |  |       
|Common Equity                   |  | $2,528.6              |  | 50.4% 
|Preferred Stock                 |  | 30.4                  |  | 0.6%  
|Long‐Term Debt (a)              |  | 1,587.2               |  | 31.6% 
|Capital Lease Obligations (a)   |  | 564.9                 |  | 11.3% 
|Short‐Term Debt                 |  | 304.2                 |  | 6.1%  
|                                |  |                       |  |       
|Total                           |  | $5,015.3              |  | 100.0%
|                                |  |                       |  |       
|                                |  |                       |  |       
|                                |  |                       |  |       
|(a) Includes current maturities |  |                       |  |       

We recorded a $335.5 million capital lease in July 2005 in connection with the in‐service date of PWGS 1.  For additional information, see Note G ‐‐ Long‐Term Debt in the Notes to Consolidated Financial Statements.

Access to capital markets at a reasonable cost is determined in large part by credit quality.  The following table summarizes the ratings of our debt securities and preferred stock by S&P, Moody's and Fitch as of December 31, 2006.



|                    |  | S&P |  | Moody's |  | Fitch
|------------------- |  | --- |  | ------- |  | -----
|                    |  |     |  |         |  |      
|                    |  |     |  |         |  |      
|Commercial Paper    |  | A‐2 |  | P‐1     |  | F1   
|Senior Secured Debt |  | A‐  |  | Aa3     |  | AA‐  
|Unsecured Debt      |  | A‐  |  | A1      |  | A+   
|Preferred Stock     |  | BBB |  | A3      |  | A    

On June 15, 2006, Fitch affirmed our security ratings.  Our security ratings outlook assigned by Fitch is stable.

On June 8, 2006, S&P affirmed our security ratings and ratings outlook.  Our security ratings outlook assigned by S&P is negative.

Our security ratings outlook assigned by Moody's is stable.

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We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms.  However, these security ratings reflect the views of the rating agencies only.  An explanation of the significance of these ratings may be obtained from each rating agency.  Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness.  Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.  Each rating should be evaluated independently of any other rating.



Capital Requirements

Total capital expenditures, excluding the purchase of nuclear fuel, are currently estimated to be approximately $600 million during 2007.  Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact us, future long‐term capital requirements may vary from recent capital requirements.  We currently expect these capital expenditures to be between $500 million and $600 million per year during the next three years.

In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc.  We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 and 200 MW.  We estimate that the capital cost of the project, excluding AFUDC, will be up to $360 million.  We anticipate the cost to build the wind farm projects would be recovered in our rates.  We expect the turbines to be placed in service in 2008, dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.  For additional information on Wind Generation see Rates and Regulatory Matters ‐ Wind Generation below.

Investments in Outside Trusts:   We have funded our pension obligations, certain other post‐retirement obligations and future nuclear obligations in outside trusts.  Collectively, these trusts had investments that exceeded $1.7 billion as of December 31, 2006.  These trusts hold investments that are subject to the volatility of the stock market and interest rates.  For further information, see Note F ‐‐ Nuclear Operations and Note L ‐‐ Benefits in the Notes to Consolidated Financial Statements.

Off‐Balance Sheet Arrangements:   We are a party to various financial instruments with off‐balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations.  We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors.  For further information, see Note M ‐‐ Guarantees in the Notes to Consolidated Financial Statements.

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FIN 46.  As a result, we do not consolidate these entities.  Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases as reflected in the table below.  We have included our contractual obligations under all three of these contracts in our Contractual Obligations/Commercial Commitments disclosure that follows.  For additional information, see Note D ‐‐ Variable Interest Entities in the Notes to Consolidated Financial Statements.

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Contractual Obligations/Commercial Commitments:   We have the following contractual obligations and other commercial commitments as of December 31, 2006:



|                                |  | Payments Due by Period
|------------------------------- |  | ----------------------
|                                |  |                       
|Contractual Obligations (a)     |  | Total                 
|                                |  |                       
|                                |  | (Millions of Dollars) 
|                                |  |                       
|Long‐Term Debt Obligations (b)  |  | $3,630.2              
|Capital Lease Obligations (c)   |  | 1,677.7               
|Operating Lease Obligations (d) |  | 183.9                 
|Purchase Obligations (e)        |  | 1,376.1               
|Other Long‐Term Liabilities (f) |  | 74.9                  
|                                |  |                       
|Total Contractual Obligations   |  | $6,942.8              
|                                |  |                       
|                                |  |                       
|                                |  |                       



|(a) | The amounts included in the table are calculated using current market prices, forward curves and other estimates.  Contracts with multiple unknown variables have been omitted from the analysis.  This table excludes the long‐term power purchase commitment which is contingent upon the sale of Point Beach.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                 
|(b) | Principal and interest payments on our Long‐Term Debt and the Long‐Term Debt of our affiliates (excluding capital lease obligations).                                                                                                                                                                           
|    |                                                                                                                                                                                                                                                                                                                 
|(c) | Capital Lease Obligations for nuclear fuel lease, PWGS 1 and purchase power commitments.                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                 
|(d) | Operating Lease Obligations for purchase power commitments and vehicle and rail car leases.                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                 
|(e) | Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation and for information technology and other services for utility operations.                                                                                                             
|    |                                                                                                                                                                                                                                                                                                                 
|(f) | Other Long‐Term Liabilities include the expected 2007 supplemental executive retirement plan obligation and the 2007 non‐discretionary pension contribution.  For additional information on employer contributions to our benefit plans see Note L ‐ Benefits in the Notes to Consolidated Financial Statements.



Our obligations for utility operations have historically been included as part of the rate making process and therefore are generally recoverable from customers.





FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate.  These risks, described in further detail below, include but are not limited to:

Regulatory Recovery:   Our electric operations burn natural gas in our leased power plants, in several of our peaking power plants and as a supplemental fuel at several coal‐fired plants.  In addition, the cost of purchased power is generally tied to the cost of natural gas.  We bear regulatory risk for the recovery of these fuel and purchased power costs when these costs are higher than the base rate established in our rate structure.  For further information on the recovery of fuel and purchase power costs see Commodity Prices.

We account for our regulated operations in accordance with SFAS 71.  Our rates are determined by regulatory authorities.  Our primary regulator is the PSCW.  SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable.  We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators.  We assume the risks and benefits of ultimate recovery of these items in future rates.  If the recovery of these costs is not approved by our

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Commodity Prices:   In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas and the cost of purchased power.  We manage our fuel and gas supply costs through a portfolio of short‐ and long‐term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.  In addition, we manage the risk of price volatility by utilizing gas hedging programs.

Wisconsin's retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation.  If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted prospectively.  For 2007, we will operate under a traditional fuel cost adjustment clause in the Wisconsin retail jurisdiction whereby fuel revenues may be adjusted prospectively if fuel and purchased power costs fall outside a pre‐established annual band of plus or minus 2%.  For information regarding the 2006 fuel rules, see Rates and Regulatory Matters.

The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for our gas utility operations through a gas cost recovery mechanism, which mitigates most of the risk of gas cost variations.  For information concerning the electric utility fuel cost adjustment procedure and our natural gas utility's GCRM, see Rates and Regulatory Matters.

Natural Gas Costs:   Significant increases in the cost of natural gas affect our electric and gas utility operations.  Natural gas costs have increased significantly because the supply of natural gas in recent years has not kept pace with the demand for natural gas. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas is added to the nation's energy supply mix.

Higher natural gas costs increase our working capital requirements and result in higher gross receipts taxes in the State of Wisconsin.  Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write‐offs as more customers are unable to pay their bills.  Because federal and state energy assistance dollars have not kept pace with rising natural gas costs over the recent year, our risks related to bad debt expenses have increased.

In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates.  In 2004 and 2003, we had approval from the PSCW to defer residential bad debt net write‐offs that exceed amounts allowed in rates.

As a result of our GCRM, our gas distribution operations receive dollar for dollar recovery on the cost of natural gas.  However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins.

Weather:   Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20‐year averages.  Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season.  Our gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season.  A summary of actual weather information in our service territory during 2006, 2005 and 2004, as measured by degree‐days, may be found above in Results of Operations.

Interest Rate:   We have various short‐term borrowing arrangements to provide working capital and general corporate funds.  We also have variable rate long‐term debt outstanding at December 31, 2006.  Borrowing levels under these arrangements vary from period to period depending upon capital investments and other factors.  Future short‐term interest expense and payments will reflect both future short‐term interest rates and borrowing levels.

We performed an interest rate sensitivity analysis at December 31, 2006 of our outstanding portfolio of $304.2 million of short‐term debt with a weighted average interest rate of 5.47% and $164.4 million of variable‐rate long‐term debt with a weighted average interest rate of 3.83%.  A one‐percentage point change in interest rates

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Marketable Securities Return:   We fund our pension, OPEB and nuclear decommissioning obligations through various trust funds, which in turn invest in debt and equity securities.  Changes in the market prices of these assets can affect future pension, other post‐retirement benefit and nuclear decommissioning expenses.  Additionally, future contributions can also be affected by changes in the market price of trust fund assets.  We expect that the risk of expense and contribution variations as a result of changes in the market price of trust fund assets would be mitigated in part through future rate actions by our various utility regulators.  Through December 31, 2005, we were operating under a PSCW‐ordered, qualified five‐year rate restriction period.  For further information about the rate restriction, see Rates and Regulatory Matters.

At December 31, 2006, we held, or Wisconsin Energy held on our behalf, the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.



|Wisconsin Electric Power Company           |  | Millions of Dollars
|------------------------------------------ |  | -------------------
|                                           |  |                    
|                                           |  |                    
|Pension trust funds                        |  | $777.2             
|Nuclear decommissioning trust funds        |  | $881.6             
|Other post‐retirement benefits trust funds |  | $119.7             

Fiduciary oversight of the pension and other post‐retirement plan trust fund investments is the responsibility of an Investment Trust Policy Committee.  Qualified external investment managers are engaged to manage the investments.  Asset/liability studies are periodically conducted with the assistance of an outside investment advisor.  The current study for the pension fund projects long‐term, annualized returns of approximately 8.5%.

Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the Investment Trust Policy Committee.  Qualified external investment managers are also engaged to manage these investments.  Asset/liability studies are periodically conducted with the assistance of an outside investment advisor, subject to additional constraints established by the PSCW.  The current study projects long‐term, annualized returns of approximately 9%.  Current PSCW constraints allow a maximum allocation of 65% in equities.

We insure various property and outage risks through NEIL.  Annually, NEIL reviews its underwriting and investment results and determines the feasibility of granting a distribution to policyholders.  Adverse loss experience, rising reinsurance costs or impaired investment results at NEIL could result in increased costs or decreased distributions to us.

Credit Ratings:   We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.  We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require, in the event of a credit ratings change to below investment grade, a termination payment if collateral is not provided or an accelerated payment.  At December 31, 2006, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $46.1 million.

Economic Conditions:   We are exposed to market risks in the regional midwest economy.

Inflation:   We continue to monitor the impact of inflation, especially with respect to the rising costs of medical plans, in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions.  Except for continuance of an increasing trend in the inflation of medical costs and the impacts on our medical and post‐retirement benefit plans, we have expectations of low‐to‐moderate inflation.  We do not believe the impact of general inflation will have a material effect on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward‐Looking Information at the beginning of this report and Risk Factors above.

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POWER THE FUTURE

Under Wisconsin Energy's PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power.  We Power will lease the new plants to us under long‐term leases, and we expect to recover the lease payments in our electric rates.  Our lease payments are based on the cash costs authorized by our primary regulator to We Power.

The PTF units include PWGS 1, PWGS 2, OC 1 and OC 2.  The following table identifies certain key items related to the units:



|Unit Name |  | Expected In Service |  | Authorized Cash Costs (a)
|--------- |  | ------------------- |  | -------------------------
|          |  |                     |  |                          
|PWGS 1    |  | July 2005 (Actual)  |  | $    333 million (Actual)
|PWGS 2    |  | Summer 2008         |  | $    329 million         
|OC 1      |  | Summer 2009         |  | $ 1,300 million          
|OC 2      |  | Summer 2010         |  | $    640 million         



|(a) | Authorized cash costs represent the PSCW approved costs and the increases for factors such as inflation as identified in the PSCW approved lease terms for PWGS 2, and adjusted for Wisconsin Energy's ownership percentages in the case of OC 1 
and OC 2.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Power the Future ‐ Port Washington

Background:   In December 2002, the PSCW issued a written order (the Port Order) granting Wisconsin Energy, us and We Power a CPCN to commence construction of the PWGS consisting of two 545 MW natural gas‐fired combined cycle generating units on the site of our existing Port Washington Power Plant.  The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral, which was completed in December 2004, and it authorized ATC to construct transmission system upgrades to serve PWGS 1 and PWGS 2.  PWGS 1 was completed in July 2005 and placed into service at that time.  PWGS 1 was completed within the PSCW approved cost parameters.  In October 2003, we received approval from FERC to transfer by long‐term lease certain associated FERC jurisdictional transmission related assets from We Power to us.  Construction of PWGS 2 is well underway.  Site preparation, including removal of the old coal units at the site, was completed in early 2006, and all of the major components have been procured.  The unit is expected to begin commercial operation in time for the peak summer season in 2008.

Lease Terms:   The PSCW approved the lease agreements and related documents under which we will staff, operate and maintain PWGS 1 and PWGS 2.  Key terms of the leased generation contracts include:

- Initial lease term of 25 years with the potential for subsequent renewals at reduced rates;
- Cost recovery over a 25 year period on a mortgage basis amortization schedule;
- Imputed capital structure of 53% equity, 47% debt;
- Authorized rate of return of 12.7% after tax on equity;
- Fixed construction cost of PWGS 1 and PWGS 2 at $309.6 million and $280.3 million (2001 dollars) subject to escalation at the GDP inflation rate;
- Recovery of carrying costs during construction; and
- Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the Port Order, which do not include the key financial terms.

In January 2003, we filed a request with the PSCW to defer costs for recovery in future rates.  The PSCW approved the request in an open meeting in April 2003.  We Power began collecting certain costs from us in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003.  We defer the lease costs on our balance sheet, and we amortize the costs to expense as we recover the costs in rates.

Legal and Regulatory Matters:   There are currently no legal challenges to the construction of PWGS and all construction permits have been received for PWGS 1 and PWGS 2.  As a result of the enactment of the Energy Policy Act, FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to

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Power the Future ‐ Oak Creek Expansion

Background:   In November 2003, the PSCW issued an order (the Oak Creek Order) granting us, along with Wisconsin Energy and We Power, a CPCN to commence construction of two 615 MW coal‐fired units (the Oak Creek expansion) to be located adjacent to the site of our existing Oak Creek Power Plant.  We anticipate OC 1 will be operational in 2009 and OC 2 will be operational in 2010.  The Oak Creek Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the State.  The total cost for the two units was set at $2.191 billion, and the order provided for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW.  The CPCN was granted contingent upon us obtaining the necessary environmental permits.  All necessary permits have been received at this time.  In June 2005, construction commenced at the site.

In November 2005, We Power completed the sale of approximately a 17% interest in the project to two unaffiliated entities, who will share ratably in the construction costs.

Lease Terms:  In October 2004, the PSCW approved the lease generation contracts between us and We Power for the Oak Creek expansion.  Key terms of the leased generation contracts include:



Legal and Regulatory Matters:   The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005.  We have received all permits necessary to commence construction.  Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge.  The major permits are discussed below.

The WDNR issued a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Oak Creek expansion.  The permit has been the subject of appeals since 2003.  The final appeal was resolved by the Wisconsin Court of Appeals in February 2006, and the period for appeal of that decision to the Wisconsin Supreme Court has expired.

We applied to the WDNR to modify the existing WPDES permit that is required for operation of the water intake and discharge system for the planned Oak Creek expansion and existing Oak Creek generating units.  In March 2005, the WDNR determined that the proposed cooling water intake structure and water discharge system meets regulatory requirements and reissued the WPDES permit with specific limitations and conditions.  The opponents filed a petition for judicial review in Dane County Circuit Court and a request for a contested case proceeding with the WDNR.  In September 2005, the judicial review petition was dismissed by agreement of the parties.  The WDNR granted a contested case hearing that was held in March 2006.  The administrative law judge upheld the issuance of the permit in a decision issued in July 2006.  In August 2006, the opponents filed for judicial review of the administrative law judge's decision upholding the issuance of the permit.  Briefing was completed in December 2006.  However, based on the federal court decision discussed below, the opponents filed a motion on January 26, 2007 requesting supplemental briefing.  In a telephone conference on February 2, 2007, the Court said that additional briefing was not necessary, but that it might request oral argument before issuing its decision regarding review of the permit.  We anticipate a decision in the case in 2007.

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On January 26, 2007, the Federal Court of Appeals for the Second Circuit issued a decision in Riverkeeper, Inc. v. EPA, Nos. 04‐6692‐ag(L) et al. (2d Cir. 2007) relating to the 316(b) rules for cooling water intake systems for existing large utility plants.  The Second Circuit Court found certain portions of the rule impermissible and remanded several parts of the rule to the EPA for further consideration or potential additional rule‐making.  The WPDES permit for our Oak Creek expansion and existing Oak Creek generating units is a state permit, issued by WDNR with concurrence of EPA.  Based on our review of the Second Circuit decision, we do not believe the decision invalidates the WPDES permit for Oak Creek.  However, we cannot predict what, if any, impact the decision may have on the court's decision in the Dane County Circuit Court case.

In May 2005, we received the Army Corps of Engineers federal permit necessary for the construction of the Oak Creek expansion.  Opponents may appeal the permit in federal court.

In addition, as a result of the enactment of the Energy Policy Act, FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to FERC's jurisdiction.  Under FERC's rules implementing the Energy Policy Act, Wisconsin Energy, us and We Power filed a joint application for FERC authorization to transfer the generating assets and limited interconnection facilities of OC 1 and OC 2 through a lease arrangement between We Power and us.  Approval was received from FERC for these leases in December 2006.



RATES AND REGULATORY MATTERS

The PSCW regulates our retail electric, natural gas and steam rates in the State of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates.  The MPSC regulates our retail electric rates in the State of Michigan.  We estimate that approximately 89% of our electric revenues are regulated by the PSCW, 5% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC.  All of our natural gas revenues are regulated by the PSCW.  Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

Overview:  For the period from March 2000 until December 31, 2005, our rates were governed by an order from the PSCW in connection with the approval of Wisconsin Energy's acquisition of WICOR.  Under this order, we were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions.

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The table below summarizes the anticipated annualized revenue impact of recent rate changes.



|                               |  | Incremental |  |          |  |                  
|------------------------------ |  | ----------- |  | -------- |  | -----------------
|                               |  | Annualized  |  | Percent  |  |                  
|                               |  | Revenue     |  | Change   |  | Effective        
|Service ‐ Wisconsin Electric   |  | Increase    |  | in Rates |  | Date             
|                               |  |             |  |          |  |                  
|                               |  | (Millions)  |  | (%)      |  |                  
|                               |  |             |  |          |  |                  
|Fuel Electric, Michigan        |  | $3.4        |  | 7.5%     |  | January 1, 2007  
|Retail electric, Wisconsin     |  | $222.0      |  | 10.6%    |  | January 26, 2006 
|Retail gas, Wisconsin          |  | $21.4       |  | 2.9%     |  | January 26, 2006 
|Retail steam, Wisconsin (a)    |  | $7.8        |  | 31.5%    |  | January 26, 2006 
|Fuel electric, Michigan        |  | $2.7        |  | 5.9%     |  | January 1, 2006  
|Fuel electric, Wisconsin (b)   |  | $7.7        |  | 0.3%     |  | November 24, 2005
|Fuel electric, Michigan        |  | $2.5        |  | 5.8%     |  | November 1, 2005 
|Retail electric, Wisconsin     |  | $59.7       |  | 3.1%     |  | May 19, 2005     
|Retail steam, Wisconsin        |  | $0.5        |  | 3.6%     |  | May 19, 2005     
|Fuel electric, Wisconsin (b)   |  | $114.9      |  | 5.9%     |  | March 18, 2005   
|Fuel electric, Michigan        |  | $3.4        |  | 8.0%     |  | January 1, 2005  
|Fuel electric, Michigan        |  | $1.3        |  | 3.1%     |  | October 1, 2004  
|Retail steam, Wisconsin        |  | $0.5        |  | 3.4%     |  | May 5, 2004      
|Retail electric, Wisconsin (c) |  | $59.0       |  | 3.3%     |  | May 5, 2004      
|Fuel electric, Michigan        |  | $3.3        |  | 7.6%     |  | January 1, 2004  



|(a) | In January 2006, the PSCW issued a final order authorizing an increase in steam rates of $7.8 million over the two year period of 2006 and 2007.                                                                                                                                                                                                                                                  
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                   
|(b) | In November 2005, the PSCW issued a final order authorizing a fuel surcharge for $7.7 million of additional fuel costs.  In March 2005, the PSCW issued an interim order authorizing a fuel surcharge for $114.9 million that was effective until the November 2005 final order was issued by the PSCW.  The final November 2005 order for $122.6 million superseded the March 2005 interim order.
|    |                                                                                                                                                                                                                                                                                                                                                                                                   
|(c) | In May 2004, the PSCW issued a final order authorizing an increase in electric rates for costs associated with the PWGS under construction and increased costs associated with low‐income energy assistance.                                                                                                                                                                                      



2006 Pricing:   In January 2006, we received an order from the PSCW that allowed us to increase annual electric revenues by approximately $222.0 million or 10.6% to recover increased costs associated with investments in Wisconsin Energy's PTFunits, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy.  The rate increase was based on an authorized return on equity of 11.2%.  The order also required us to refund to customers, with interest, any fuel revenues that we receive that are in excess of fuel and purchased power costs that we incur, as defined by the Wisconsin fuel rules.  The original order stipulated that any refund would also include interest at short‐term rates.  This refund provision does not extend past December 31, 2006.

During 2006, we experienced lower than expected fuel and purchased power costs.  In September 2006, we requested and received approval from the PSCW to refund favorable fuel recoveries including accrued interest at a short‐term rate.  In addition, in September 2006 the PSCW determined that if the total recoveries for 2006 exceeded $36 million, interest on the amount in excess of $36 million would be paid at the rate of 11.2%, our authorized return on equity rather than at short‐term rates as originally set forth in the order.  During October 2006, we refunded $28.7 million, including interest, to Wisconsin retail customers as a credit on their bill and we received approval from the PSCW to refund an additional $10 million, including interest, in the first quarter of 2007.

For 2007, we expect to operate under a traditional fuel cost adjustment clause in the Wisconsin retail jurisdiction whereby fuel revenues may be adjusted prospectively if fuel and purchased power costs fall outside a pre‐established annual band of plus or minus 2%.

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Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base.  The January 2006 order provided for an increase in gas revenues totaling $21.4 million or 2.9%.  The rate increase was based on an authorized return on equity of 11.2%.

The steam rate proceeding was a traditional rate proceeding.  The January 2006 order provided for an increase in steam rates of $7.8 million or 31.5% to be phased in over a two year period beginning in 2006.  The rate increase was based on an authorized return on equity of 11.2%.

2008 Pricing:   We anticipate filing a rate case in May 2007 for new rates effective in January 2008.



Limited Rate Adjustment Requests

2005 Fuel Recovery Filing:   In February 2005, we filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source.  We received approval for the increase in fuel recoveries on an interim basis in March 2005.  In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%).  In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from Wisconsin Energy's acquisition of WICOR.  As a condition of the PSCW approval of Wisconsin Energy's WICOR acquisition, we were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger.  In July 2006, the Dane County Circuit Court affirmed the PSCW's decision.  In August 2006, the opponents appealed this decision to the Wisconsin Court of Appeals.  We anticipate a decision from the Wisconsin Court of Appeals in 2007.

2005 Revenue Deficiencies:   In May 2004, we filed an application with the PSCW for an increase in electric and steam rates for anticipated 2005 revenue deficiencies associated with (1) costs for the new PWGS and the Oak Creek expansion being constructed as part of Wisconsin Energy's PTF strategy, (2) costs associated with our energy efficiency procurement plan and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway project in downtown Milwaukee, Wisconsin.  The filing identified anticipated revenue deficiencies in 2005 attributable to Wisconsin in the amount of $84.8 million (4.5%) for our electric operations and $0.5 million (3.6%) for our steam operations.  In January 2005, as a result of the litigation involving the Oak Creek expansion, we amended this filing to reduce the total revenue request to $52.4 million.  In May 2005, the PSCW issued its final written order implementing an annualized increase in electric rates of $59.7 million (3.1%) and an increase of $0.5 million (3.6%) in steam rates.



Other Utility Rate Matters

Electric Transmission Cost Recovery:   We divested our transmission assets with the formation of ATC in January 2001.  We now procure transmission service from ATC at FERC approved tariff rates.  In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within ATC and increased transmission infrastructure requirements in the state.  In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed the deferral of transmission costs in excess of amounts imbedded in rates.  We are allowed to earn a return on the unrecovered transmission costs at our weighted average cost of capital.  As of December 31, 2006, we have deferred $192.2 million of unrecovered transmission costs.  In January 2006, our rates were increased by approximately $67.5 million annually to recover transmission costs that were not currently in rates.  We will continue to accrue carrying costs on the unrecovered balances.

Fuel Cost Adjustment Procedure:   Within the State of Wisconsin, we operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts.  Imbedded within our base rates is an amount to recover fuel costs.  Under the current fuel rules, no adjustments are made to rates as long as fuel and purchased power costs are expected to be within a band of the costs imbedded in current rates for the twelve month period ending December 31.  If, however, annual fuel costs are expected to fall outside of the band, and actual costs fall outside of established fuel bands, then we may file for a

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In June 2006, the PSCW opened a docket (01‐AC‐224) in which it was looking into revising the current fuel rules (Chapter PSC 116).  In February 2007, five Wisconsin utilities regulated by the fuel rules including us, filed a joint proposal to modify the existing rules in this docket.  The proposal recommends modifying the rules to allow for escrow accounting for fuel costs outside a plus or minus 1% annual band width of fuel costs allowed in rates.  It further recommends that the escrow balance be trued‐up annually following the end of each calendar year.  We are unable to predict if or when the PSCW will make any changes to the existing fuel rules.

Our electric operations in Michigan operate under a Power Supply Cost Recovery mechanism which generally allows for the recovery of fuel and purchase power costs on a dollar for dollar basis.

Gas Cost Recovery Mechanism:   Our natural gas operations operate under a GCRM as approved by the PSCW.  Generally, the GCRM allows for a dollar for dollar recovery of gas costs.  There is an incentive mechanism under the GCRM which allows for increased revenues if we acquire gas lower than benchmarks approved by the PSCW.  During 2006 and 2005, no additional revenues were earned under the incentive portion of the GCRM and $0.2 million of additional revenues were earned in 2004 under the GCRM.

Bad Debt Costs:    In 2004, due to a combination of unusually high natural gas prices, a soft economy within our utility service territories, and limited governmental assistance available to low‐income customers, we saw a significant increase in residential uncollectible accounts receivable.  These factors led us to request and receive letters from the PSCW which allowed us to defer the costs of residential bad debts to the extent that the costs exceeded the amounts allowed in rates.  As a result of these letters from the PSCW, we deferred approximately $11.7 million in 2004 related to bad debt costs.

In January 2006, the PSCW issued an order approving the amortization over the next five years of the bad debts deferred in 2004 for our gas operations.  The bad debts deferred in 2004 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.

In December 2004, we filed with the PSCW a request to implement a pilot program, which, among other things, is designed to better match our collection efforts with the ability of low income customers to pay their bills.  Included in this filing was a request to implement escrow accounting for all residential bad debt costs.  In February 2005, the PSCW approved our pilot program and our request for the use of escrow accounting.  The final decision was received in March 2005.  The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates.  As a result of this approval from the PSCW, we escrowed approximately $6.0 million in 2006 and $9.7 million in 2005 related to bad debt costs.  These amounts were not addressed in the January 2006 rate order, and will therefore be considered for recovery in future rates, subject to audit and approval of the PSCW.  We will continue following the escrow method of accounting for bad debts as approved in the March 2005 PSCW order.

MISO Midwest Market:   In January 2005, we requested deferral accounting treatment from the PSCW for certain incremental costs or benefits that may occur due to the implementation on April 1, 2005 of the MISO Midwest Market.  We received approval for this accounting treatment in March 2005.  Additionally, in March 2005 we submitted a joint proposal to the PSCW with other utilities requesting escrow accounting treatment for the MISO Midwest Market costs until each utility's first rate case following April 1, 2008.  The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment.  The PSCW approved deferral treatment for these costs in June 2006.  For additional information see Industry Restructuring and Competition ‐‐ Electric Transmission and Energy Markets ‐‐ MISO.

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Wholesale Electric Rates:   On August 1, 2006, we filed a wholesale rate case with FERC.  The filing requests an annual increase in rates of approximately $16.7 million applicable to four existing wholesale electric customers.  In November 2006, FERC accepted the rate filing subject to refund with interest; however, the rates have not yet been approved.  Three of the existing customer's rates are effective January 1, 2007 and the remaining $16.5 million for the largest wholesale customers' rates will be effective May 1, 2007.  The rates are subject to refund and hearing and settlement procedures.

Depreciation Rates:   In January 2005, along with Wisconsin Gas, we filed a joint application with the PSCW for certification of depreciation rates for specific classes of utility plant assets.  In November 2005, we received notice from the PSCW that the proposed estimated lives, net salvage values and depreciation rates were approved and became effective January 1, 2006.  For more information, see Note A ‐‐ Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

Nuclear Refueling Outages ‐ 2005:   In May 2005, we requested and received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer‐than‐expected outage at Point Beach Unit 2.  We deferred $22.1 million of incremental purchased power costs related to the extended outage.

Renewables, Efficiency and Conservation:   In March 2006, Wisconsin enacted new public benefits legislation, Act 141. This legislation changes the renewable energy requirements for utilities.  Act 141 requires Wisconsin utilities to provide 2% more of their total retail energy from renewable resources than their current levels by 2010, and 6% more renewable energy than their current levels by 2015.  Act 141 establishes a statewide goal that 10% of all electricity in Wisconsin be generated by renewable resources by December 31, 2015.  Assuming the bulk of additional renewables is wind turbines, we must obtain approximately 210 MW of additional renewable capacity by 2010 and another approximately 610 MW of additional renewable capacity by 2015 to meet the retail energy delivered requirements.  We have already started development of additional sources of renewable energy to comply with commitments made as part of Wisconsin Energy's PTF initiative which will assist us in complying with Act 141.  See Wind Generation discussion below.

Act 141 allows the PSCW to delay a utility's implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would be too expensive or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities.  The previous law did not include similar provisions.  Act 141 provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility is considered in compliance with the Energy Priorities law.  Prior to Act 141, there had been no agreement on how to determine compliance with the Energy Priorities law, which provides that it is the policy of the PSCW, to the extent it is cost‐effective and technically feasible, to consider the following options in the listed order when reviewing energy‐related applications: (1) energy conservation and efficiency, (2) noncombustible renewable energy resources, (3) combustible renewable energy resources, (4) natural gas, (5) oil or low sulfur coal and (6) high sulfur coal and other carbon‐based fuels.

We are evaluating the requirements of Act 141.  Additionally, the details of the new requirements are subject to administrative rulemaking that could take until March 2007 to complete.

Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the DOA back to the utilities and/or contracted third parties.  In addition, the law requires that 1.2% of utilities' operating revenues be set aside for these programs.  We do not expect the impact of this action to be material as the 1.2% approximates the amounts currently in our rates for these matters.  The effective date of this action is July 1, 2007.  The PSCW is expected to develop implementation plans over the upcoming months.

Wind Generation:   In June 2005, we purchased the development rights to two wind farm projects (Blue Sky Green Field) from Navitas Energy Inc.  We plan to develop the wind sites and construct wind turbines with a combined generating capacity of between approximately 130 and 200 MW.  We filed for approval of a CPCN with the PSCW in March 2006.  A prehearing conference was held in September 2006.  In addition, our direct testimony was filed in September 2006.  Staff and intervenor testimony was filed in October 2006 and rebuttal testimony by all parties was filed in November 2006.  Hearings were held at the end of November 2006.  In February 2007, the PSCW issued a written notice approving the CPCN.  In addition to the CPCN approval, we are working to secure any additional

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We estimate that the capital cost of the project, excluding AFUDC, will be up to $360 million.  The demand for wind turbine equipment has been strong, pushing off equipment deliveries to dates later than originally anticipated.  We currently expect the turbines to be placed in service by the end of 2008, dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.



ELECTRIC SYSTEM RELIABILITY

In response to customer demand for higher quality power required by modern equipment, we are evaluating and updating our electric distribution system.  We are taking steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability.  These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near‐term efforts to enhance our current electric distribution infrastructure.  For the long‐term, we have developed a distribution system asset management strategy that requires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy.

We had adequate capacity to meet all of our firm electric load obligations during 2006.  All of our generating plants performed well during the warmest periods of the summer and all power purchase commitments under firm contract were received.  During this period, public appeals for conservation were not required; however, pursuant to MISO's orders we did interrupt or curtail service to non‐firm customers who participate in load management programs in exchange for discounted rates.

We expect to have adequate capacity to meet all of our firm load obligations during 2007.  However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures during 2007 as we have in past years.



ENVIRONMENTAL MATTERS

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation challenges related to current and past operations.  Specific environmental issues affecting our utility and non‐utility energy segments include but are not limited to (1) air emissions such as CO2, SO2, NOx, small particulates and mercury, (2) disposal of combustion by‐products such as fly ash, (3) remediation of former manufactured gas plant sites, (4) disposal of used nuclear fuel and (5) the eventual decommissioning of Point Beach.

We are currently pursuing a proactive strategy to manage our environmental issues including (1) substituting new and cleaner generating facilities for older facilities as part of Wisconsin Energy's PTF strategy, (2) developing additional sources of renewable electric energy supply, (3) water quality matters such as discharge limits and cooling water requirements, (4) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules, (5) entering into agreements with the WDNR and EPA to reduce emissions of SO2 and NOx by more than 65% and mercury by 50% by 2013 from our coal‐fired power plants in Wisconsin and Michigan, (6) evaluating and implementing improvements to our cooling water intake systems, (7) recycling of ash from coal‐fired generating units and (8) the clean‐up of former manufactured gas plant sites.  The capital cost of implementing the EPA consent decree is estimated to be approximately $1 billion over the 10 years ending 2013.  These costs are principally associated with the installation of air quality controls on Pleasant Prairie Units 1 and 2 and Oak Creek Units 5‐8.  Through December 31, 2006, we have spent approximately $355.0 million associated with implementing the EPA agreement.  For further information concerning the consent decree, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements.  For further information concerning disposal of used nuclear fuel and nuclear power plant decommissioning, see Nuclear Operations below and Note F ‐‐ Nuclear Operations in the Notes to Consolidated Financial Statements, respectively.

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National Ambient Air Quality Standards:   In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the NAAQS for 1‐hour ozone. In 2004, the EPA began implementing NAAQS for 8‐hour ozone and PM 2.5.  The states are currently developing rules to implement the new standards.  Although specific emission control requirements are not yet defined, we believe that the revised standards will likely require significant reductions in SO2 and NOx emissions from coal‐fired generating facilities.  We expect that reductions needed to achieve compliance with the 8‐hour ozone attainment standard will be implemented in stages.  Reductions associated with the fine particulate matter standards are expected to be implemented in stages after the year 2010 and extending to the year 2017.  We are currently unable to predict the impact that the revised air quality standards might have on the operations of our existing coal‐fired generating facilities until the states develop rules and submit State Implementation Plans (SIP) to the EPA to demonstrate how they intend to comply with the 8‐hour ozone and fine particulate matter NAAQS.

8‐hour Ozone Standard:   In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment areas for the 8‐hour ozone NAAQS.  States are required to develop and submit SIPs to the EPA by June 2007 to demonstrate how they intend to comply with the 8‐hour ozone NAAQS.  We expect that reductions needed to achieve compliance with the 8‐hour ozone attainment standard will be implemented in stages, and that some or all of these reductions will be accomplished through implementation of the CAIR.  See below for further information regarding CAIR.  We believe that compliance with the NOx emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the EPA's 8‐hour ozone NAAQS.  However, the timing of the requirements may be impacted by requiring earlier installation of NOx controls at some units, depending on how the states implement the rules.

PM2.5Standard:   In December 2004, the EPA designated PM2.5 nonattainment areas in the country.  All counties in the State of Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard.  It is unknown at this time whether Wisconsin or Michigan will require additional emission reductions as part of state or regional implementation of the PM2.5standard and what impact those requirements would have on operation of our existing coal‐fired generation facilities.

Clean Air Interstate Rule:  The EPA issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8‐hour ozone and PM2.5 standards by addressing the regional transport of SO2 and NOx.  CAIR requires NOx and SO2 emission reductions in two phases from electric generating units located in a 28‐state region within the eastern United States.  Wisconsin and Michigan are affected states under CAIR.  The phase 1 compliance deadline is January 1, 2009 for NOx and January 1, 2010 for SO2, and the phase 2 compliance deadline is January 1, 2015 for both NOx and SO2.  Overall, the CAIR is expected to result in a 70% reduction in SO2emissions and a 65% reduction in NOx emissions from 2002 emission levels.  The states are required to develop and submit implementation plans by no later than March 2007.  In Wisconsin, a final CAIR rule has been approved by the WDNR and is proceeding through the administrative process.  Although the impacts are uncertain until the states' implementation plans are in place, we believe that compliance with the NOx and SO2 emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

Clean Air Mercury Rule:    The EPA issued the final CAMR in March 2005 following the agency's 2000 regulatory determination that utility mercury emissions should be regulated.  CAMR limits mercury emissions from new and existing coal‐fired power plants, and caps utility mercury emission in two phases, applicable in 2010 and 2018.  The caps limit emissions at approximately 20% and ultimately 70% below today's utility mercury levels.  The states were required to develop and submit implementation plans by November 2006, but neither state has finalized its plan yet.  Until those plans are in place, it is not possible to estimate the final impact of the CAMR, but additional expenditures are anticipated in order to meet both phases of the federal rule.  Because the technology is under development, it is difficult to estimate the cost.  We believe the range of possible expenditures could be approximately $50 million to $200 million.  The construction air permit issued for the Oak Creek expansion is not impacted by the new rule.

The federal rule is being challenged by a number of states including Wisconsin and Michigan.  Depending on the litigation, the timing for compliance may be affected.

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The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin and issued state‐only mercury control rules in October 2004.  The rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program.  The rules state that the WDNR must adopt state rule changes within 18 months of publication of any federal rules.  State rules are to be changed to be consistent with, and no more restrictive than, any federal rules.  It is not possible to determine if there will be requirements in addition to CAMR until a rule is in place or the existing rule is set aside.  Because the 18 month deadline has passed, we are reviewing our options.

Clean Air Visibility Rule:   The EPA issued the CAVR in June 2005 to address regional haze, or regionally‐impaired visibility caused by multiple sources over a wide area.  The rule defines BART requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR.  Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation's 156 Class I protected areas.  States then determine the types of emission controls that those facilities must use to control their emissions.  The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia.  States must submit plans to implement CAVR to the EPA by December 2007.  The reductions associated with the state plans are scheduled to begin to take effect in 2014 with full implementation before 2018.  We are currently unable to predict the impact that CAVR might have on the operations of our existing coal‐fired generating facilities until the states develop rules and submit implementation plans to the EPA.

Clean Water Act:   Section 316(b) of the CWA requires that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact.  This law dates back to 1972; however, prior to September 2004, there were no federal rules that defined precisely how states and EPA regions determined that an existing intake met BTA requirements.  This rule established, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes.  Costs associated with implementation of the rule for our Oak Creek Power Plant, We Power's Oak Creek expansion and PWGS have been included in project costs.  Studies to determine what costs, if any, that may be associated with our other existing facilities are expected to take place over the next two years.

On January 26, 2007, the Federal Court of Appeals for the Second Circuit issued a decision concerning the 316(b) rule for existing facilities (Riverkeeper, Inc. v. EPA, Nos. 04‐6692‐ag(L) (2d Cir. 2007)).  The Second Circuit Court found certain portions of the rule impermissible and remanded several parts of the rule to the EPA for further consideration or potential additional rulemaking.  Until such time as the EPA completes those actions, we cannot predict what impact the changes, if any, to the rule may have on our facilities.

Manufactured Gas Plant Sites:   We are voluntarily reviewing and addressing environmental conditions at a number of former manufactured gas plant sites.  For further information, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Ash Landfill Sites:   We aggressively seek environmentally acceptable, beneficial uses for our combustion byproducts.  For further information, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements.

EPA ‐ Proposed Consent Decree:    We entered into a proposed consent decree with the EPA to address all matters relating to information requests received from the EPA pursuant to Section 114(a) of the Clean Air Act.  For further information, see Note Q ‐‐ Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Greenhouse Gases:   There have been international efforts seeking legally binding reductions in emissions of greenhouse gases, principally CO2, including the United Nations Framework Convention on Climate Change held in Kyoto, Japan.  While the Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other legislation requiring reductions in CO2, in 2002, the Bush Administration announced a goal of reducing the greenhouse gas intensity of the U.S. economy by 18% by 2012.  In addition, in December 2004, the DOE announced the Climate VISION program in furtherance of reduced greenhouse gas emissions.  We continue to take voluntary measures to reduce our emissions of greenhouse gases. However, legislative proposals that would impose mandatory restrictions on CO2 continue to be considered in Congress.  The impact of any future legislation that would require reductions in greenhouse gases cannot be assessed at this time.

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We continue to support flexible, market‐based strategies to curb greenhouse gas emissions.  These strategies include emissions trading, joint implementation projects and credit for early actions.  We also support a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.

Our emissions in future years will continue to be influenced by several actions completed, planned or underway as part of Wisconsin Energy's PTF strategy, including:

- Repowering the Port Washington Power Plant from coal to natural gas combined cycle units.
- Adding coal‐fired units using state‐of‐the‐art technology as part of the Oak Creek expansion.
- Increasing investment in energy efficiency and conservation.
- Maintaining and increasing non‐emitting generation by potentially adding approximately 130 to 200 MW of wind capacity and increasing customer participation in the Energy for Tomorrow® renewable energy program.
- Successful renewal of the Point Beach units' operating licenses.



LEGAL MATTERS

Arbitration Proceedings:   Our largest electric customers, two iron ore mines, operate in the Upper Peninsula of Michigan.  The mines represent approximately 6% to 7% of our annual electric sales; however, the earnings are insignificant to us.  The mines have special negotiated contracts that expire in December 2007.  The contracts have price caps for approximately 80% of the energy sales.  We do not recognize revenue on amounts billed that exceed the price caps.

The incremental power costs in the Upper Peninsula of Michigan are now determined by MISO.  In April 2005, we began to bill the mines the incremental power costs as quantified by the MISO Midwest Market.  The mines have notified us that they are disputing these billings and a portion of these disputed amounts have been deposited in escrow.  In September 2005, the mines notified us that they filed for formal arbitration related to the contracts.  We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contracts.  The arbitration hearings previously scheduled for October 2006 have been postponed and rescheduled for the third quarter of 2007, and we anticipate a decision in the fourth quarter of 2007.  As of December 31, 2006, the mines have placed $29.3 million in escrow.  As of December 31, 2005, the mines had placed $70.6 million in escrow.  The decrease in the escrow balance relates to amounts that we refunded without interest for the amounts billed in 2005 that exceeded the price caps.  At this time, we are unable to predict the outcome of the formal arbitration process, but we believe that it will not have a material adverse impact on our financial condition or results of operations.

Although it is currently uncertain, we anticipate that we will provide power to the mines under the terms of one or more regulated tariffs to be approved by the MPSC beginning January 1, 2008.

Stray Voltage:   On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin's investor‐owned utilities.  The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer.  Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.

In recent years, dairy farmers have commenced actions or made claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage, and more recently, ground currents resulting from the operation of its electrical system, even though that electrical system has been operated within the parameters of the PSCW's order.  In 2003, the Wisconsin Supreme Court upheld a Court of Appeals' affirmance of a jury verdict against us, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit.  The Supreme Court rejected the argument that if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not be found negligent in stray voltage cases.  Additionally, the Court held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation.

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As a result of this case, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW level of concern.  Even though the claims which have been made against us with respect to stray voltage and ground currents are not expected to have a material adverse effect on our financial statements, we continue to evaluate various options and strategies to mitigate this risk.



NUCLEAR OPERATIONS

Point Beach Nuclear Plant:   We own two 518 MW electric generating units (Unit 1 and Unit 2) at Point Beach in Two Rivers, Wisconsin.  Point Beach is operated by NMC, a joint venture of the Company and affiliates of other unaffiliated utilities.  During 2006, 2005 and 2004, Point Beach provided approximately 25.7%, 20.3% and 24.4%, respectively, of our net electric energy supply.

Each unit at Point Beach has a scheduled refueling outage approximately every 18 months.  A refueling outage is scheduled for Unit 1 during the first quarter of 2007.  In the fourth quarter of 2006, Unit 2 had a scheduled refueling outage.  In 2005, Unit 2 had a scheduled refueling outage over the second and third quarters and Unit 1 had a scheduled refueling outage over the third and fourth quarters.  During the 2005 scheduled refueling outages we replaced the reactor vessel heads at each unit.  As expected, this work, along with other planned maintenance, resulted in longer than normal outages.  During scheduled refueling outages, we incur significant operations and maintenance costs for work performed during the outages and we incur costs associated with replacement power.  See Results of Operations for further discussion regarding the costs associated with nuclear outages.  In 2004, Unit 1 had a scheduled refueling outage in the second quarter.

In December 2005, the NRC approved the request of NMC and us for license renewal.  The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2.

In February 2006, we announced that we were undertaking a formal review during 2006 regarding our options for the ownership and operation of Point Beach.  At December 31, 2006, NMC operated six nuclear generating units.  In addition, another owner has announced the planned sale of its unit.  This sale would further reduce the size of the fleet operated by NMC.  Given these changes, we believed it was prudent to evaluate a range of options for Point Beach.  The options that we evaluated included: (1) continued operation by NMC, (2) continued operation by a third party operator other than NMC, (3) a return to in‐house operation of the plant by us, (4) a sale of the Point Beach facility and (5) a partial sale of the plant with us retaining a minority interest in the plant.  Under this fifth option, the new majority owner would operate the plant.  As part of our continuing review, we invited qualified third parties to tour Point Beach and review the data necessary to submit a bid to operate the plant or purchase all or part of the plant and operate it.  We evaluated the bids received in comparison to continued operation of Point Beach by NMC or us.  In December 2006, we announced that we had reached a definitive agreement to sell Point Beach to an affiliate of FPL.  If and when the sale is completed (or earlier if an interim operating agreement with FPL is activated by us), NMC would transfer Point Beach's operating licenses to the buyer and we would withdraw from NMC and our relationship with NMC would be terminated.  We would be required to pay a termination fee of approximately $12 million to withdraw from NMC.  In addition, Wisconsin Energy would be required to write‐off its investment in NMC, which is approximately $5 million at December 31, 2006.  We also entered into a long‐term power purchase agreement to purchase all of the existing capacity and energy of the plant, which will become effective upon the closing of the sale.  We will have the unilateral option, subject to PSCW direction, to select a term for the power purchase agreement of either (i) an estimated 23 years for Unit 1 and 26 years for Unit 2, or (ii) 16 years for Unit 1 and 17 years for Unit 2.  The sale of the plant and the long‐term power purchase agreement are subject to review and approval by various regulatory agencies including the NRC, PSCW, MPSC and FERC.  We have submitted a request to the PSCW to defer any gain (net of transaction related costs) as a regulatory liability that would be applied to the benefit of our customers in future rate proceedings.

In July 2000, our senior management authorized the commencement of initial design work for the power uprate of both units at Point Beach.  Subject to approval by the PSCW, the project could add approximately 90 MW of electrical output to Point Beach.  In February 2003, Point Beach completed an equipment upgrade which resulted in a capacity increase of 7 MW per generating unit.  If the proposed sale of Point Beach is completed, the uprate will be the responsibility of the new owner, FPL.  In light of this, both companies are currently evaluating the timing for implementation of the power uprate project.

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During 2002 and 2003, the NRC issued Final Significance Determination letters for two red (high safety significance) inspection findings regarding problems identified by Point Beach with the performance of the auxiliary feedwater system recirculation lines.  During 2003, the NRC conducted a three‐phase supplemental inspection of Point Beach in accordance with NRC Inspection Procedure 95003 to review corrective actions for the findings as well as the effectiveness of the corrective action, emergency preparedness and engineering programs.

The inspection results were presented at a public meeting in December 2003, and documented in a February 2004 NRC letter to NMC.  The NRC determined that the plant is being operated in a manner that ensures public safety but also identified several performance issues in the areas of problem identification and resolution, emergency preparedness, electrical design basis calculation control and engineering‐operations communication.

NMC responded to the supplemental inspection in February 2004 with specific commitments to address the NRC concerns, including revision of the Point Beach Excellence Plan.  We were assessed a fine of $60,000 related to issues identified with our emergency preparedness.  NRC reviewed the adequacy of the revised Excellence Plan and its implementation, and NMC received a confirmatory action letter in April 2004.  Since then, the NRC has conducted numerous inspections and completed reviews of activities and meetings, noting the overall results were satisfactory.  As a result, in the fourth quarter of 2006, the NRC closed the confirmatory action letter and concluded that the red findings received in 2002 and 2003 will no longer be considered in the NRC's assessment process.  Point Beach will now receive routine baseline inspection by the NRC.

As a result of the September 11, 2001 terrorist attacks, NRC and the industry have been strengthening security at nuclear power plants.  Security at Point Beach remains at a high level, with limited access to the site continuing.  Point Beach has responded to NRC's February 2002 Order for interim safeguards and security compensatory measures.  Point Beach has also responded to NRC orders regarding security of independent spent fuel storage installations, design basis threat and security officer training and work hours.

Used Nuclear Fuel Storage and Disposal:   We are authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48‐canister capacity of the dry fuel storage facility.  The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed by the NRC in December 2005.

Temporary storage alternatives at Point Beach are necessary until the DOE takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987.  The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel.  Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we have paid a total of $215.2 million into the Nuclear Waste Fund over the life of Point Beach.

On August 13, 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the DOE's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims.  Consequently, we filed a complaint on November 16, 2000 against the DOE in the Court of Federal Claims.  In October 2004, the Court of Federal Claims granted our motion for summary judgment on liability.  The Court has subsequently scheduled a trial to determine damages for September 2007.  We have incurred substantial damages to date and damages continue to accrue.  We are seeking recovery of our damages in this lawsuit and we expect that any recoveries would be considered in setting future rates.

In July 2002, the President signed a resolution which allowed the DOE to begin preparation of the application to the NRC for a license to design and build a spent fuel repository in Yucca Mountain, Nevada.  In July 2006, the DOE announced plans to submit a license application to the NRC for a nuclear waste repository at Yucca Mountain no later than June 30, 2008.  The DOE also announced if the requested legislative changes are enacted, the repository would be able to accept spent nuclear fuel starting in early 2017.  It is not possible, at this time, to predict with certainty when the DOE will actually begin accepting used nuclear fuel.

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INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes.  FERC continues to support large RTOs, which will affect the structure of the wholesale market.  To this end, the MISO implemented a bid‐based market, the MISO Midwest Market, including the use of LMP to value electric transmission congestion and losses.  The MISO Midwest Market commenced operation on April 1, 2005.  Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.  It is uncertain when retail access might be implemented in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations.  In August 2005, President Bush signed into law the Energy Policy Act, which impacts the electric utility industry.  (See Other Matters below for additional information on the Energy Policy Act).  In addition, major issues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2006 and prior years.  We continue to focus on infrastructure issues through Wisconsin Energy's PTF growth strategy.

Restructuring in Wisconsin:   Electric utility revenues in Wisconsin are regulated by the PSCW.  Due to many factors, including relatively competitive electric rates charged by the state's electric utilities, the PSCW has been focused in recent years on electric reliability infrastructure issues for the State of Wisconsin.  These issues include:

- Addition of new generating capacity in the state;
- Modifications to the regulatory process to facilitate development of merchant generating plants;
- Development of a regional independent electric transmission system operator;
- Improvements to existing and addition of new electric transmission lines in the state; and
- Addition of renewable generation.

The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature.  No such legislation has been introduced in Wisconsin to date.

Restructuring in Michigan:   Electric utility revenues are regulated by the MPSC.  In June 2000, the Governor of Michigan signed the "Customer Choice and Electric Reliability Act" into law empowering the MPSC to implement electric retail access in Michigan.  The new law provides that as of January 1, 2002, all Michigan retail customers of investor‐owned utilities have the ability to choose their electric power producer.

As of January 1, 2002, our Michigan retail customers were allowed to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service.  We have maintained our generation capacity and distribution assets and provide regulated service as we have in the past.  We continue providing distribution and customer service functions regardless of the customer's power supplier.

Competition and customer switching to alternative suppliers in our service territory in Michigan has been limited.  With the exception of two general inquiries, no alternate supplier activity has occurred in our service territory in Michigan, reflecting the small market area, our competitive regulated power supply prices and a lack of interest in general in the Upper Peninsula of Michigan as a market for alternative electric suppliers.

Restructuring in Illinois:   In 1999, the State of Illinois passed legislation that introduced retail electric choice for large customers and introduced choice for all retail customers in May 2002.  This legislation has not had, and is not expected to have a material impact on our business.  We had one wholesale customer in Illinois, the City of Geneva, whose contract expired on December 31, 2005.



Electric Transmission and Energy Markets

ATC:    ATC is regulated by FERC for all rate terms and conditions of service and is a transmission‐owning member of MISO.  As of February 1, 2002, operational control of ATC's transmission system was transferred to MISO, and we became a non‐transmission owning member and customer of MISO.

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MISO:   In connection with its status as a FERC approved RTO, MISO implemented a bid‐based energy market, the MISO Midwest Market, which commenced operations on April 1, 2005.  As part of this energy market, the MISO developed a market‐based platform for valuing transmission congestion and losses premised upon the LMP system that has been implemented in certain northeastern and mid‐Atlantic states.  The LMP system includes the ability to mitigate or eliminate congestion costs through the use of FTRs.  FTRs are allocated to market participants by MISO.  A new allocation of FTRs was completed for the period of June 1, 2006 through May 31, 2007.  We were granted substantially all of the FTRs that we were permitted to request during the allocation process.  Previously, our unhedged congestion costs had not been explicitly identified and were embedded in our fuel and purchased power expenses.  Due to certain changes in the units that MISO is dispatching, our unhedged congestion costs increased in 2006.  These incremental congestion charges are deferred as approved by the PSCW, and we expect to recover these costs in future rates, subject to review and approval by the PSCW.

MISO deferred the costs to develop and start‐up its energy market (new software systems and personnel).  Now that the market is operational, the development and start‐up costs are charged to MISO market participants, including us.

To mitigate the risks of this new bid‐based energy market, we requested deferral accounting treatment from the PSCW in January 2005 for certain incremental costs or benefits that may occur due to the implementation of the MISO Midwest Market.  Our request excluded LMP energy costs because these costs are subject to recovery under the Wisconsin Fuel Cost Adjustment Procedure.  In March 2005, the PSCW accepted our request.  We submitted another joint proposal with other utilities in March 2005, requesting escrow accounting treatment for MISO Midwest Market costs until each utility's first rate case following April 1, 2008.  The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment.  The PSCW approved deferral treatment for these costs in June 2006.

In MISO, base transmission costs are currently being paid by LSE's located in the service territories of each MISO transmission owner.  The current license plate transmission rate design is scheduled to be replaced on February 1, 2008.  A filing delineating a new rate design, or substantiation for maintaining the existing rate design is due at FERC by August 1, 2007.  At this time, we are not able to determine the impact of this rate design change on our transmission costs.  FERC also ordered a seams elimination charge to be paid by MISO LSE's from December 1, 2004 until March 31, 2006, to compensate transmission owners for the loss of revenues resulting from the joining of a RTO and/or FERC's elimination of through and out transmission charges between the MISO and PJM.  FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006.  The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order.  In January 2006, along with certain other parties to the proceeding, we submitted an offer of settlement to the presiding administrative law judge that resolved all issues set for hearing that impact us with regard to the continued payment of through and out transmission charges as well as the seams elimination charge.  The administrative law judge certified the settlement to FERC, and FERC approved the settlement in April 2006.

In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee charges.  FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005.  In October 2006, we received a ruling from FERC.  Since the ruling, FERC's order has been challenged by MISO and numerous other market participants.  Any resettlement associated with the order is expected in 2007 and early 2008.  Due to the complexity of the order, we are unable to precisely determine the overall financial implication to us.  However, we do not believe that the result will have a material impact on our results of operations.

MISO is in the process of developing a market for two ancillary services, regulation reserves and contingency reserves.  The MISO ancillary services market is currently proposed to begin in 2008.  We currently self‐provide both regulation reserves and contingency reserves.  In the MISO ancillary services market, we expect that we will buy/sell regulation and contingency reserves from/to the market.  The MISO ancillary services market is expected to reduce overall ancillary services costs in the MISO footprint.  We anticipate achieving a net reduction in fuel costs, but are unable to determine the amount of savings we will realize at this time.  The MISO ancillary services market is expected to also enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

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Natural Gas Utility Industry

Restructuring in Wisconsin:   The PSCW previously instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the natural gas industry.  To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates.  However, work on deregulation of the gas distribution industry by the PSCW is presently on hold.  Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.



OTHER MATTERS

Energy Policy Act:   In August 2005, President Bush signed into law the Energy Policy Act.  Among other things, the Energy Policy Act includes tax subsidies for electric utilities and the repeal of PUHCA 1935.  The Energy Policy Act also amends federal energy laws and provides FERC with new oversight responsibilities for the electric utility industry.  Implementation of the Energy Policy Act requires the development of regulations by federal agencies, including FERC.  As noted above, the Energy Policy Act and corresponding rules required us to seek FERC authorization to allow us to lease from We Power the three PTFunits that are currently being constructed by We Power.  We received approval of these leases from FERC in December 2006.  Additionally, the Energy Policy Act repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to FERC.  We were an exempt holding company under PUHCA 1935, and, accordingly, were exempt from that law's provisions other than with respect to certain acquisitions of securities of a public utility.  In March 2006, we filed with FERC notification of our status as a holding company as required under FERC regulations implementing PUHCA 2005 and a request for exempt status similar to that held under PUHCA 1935.  In June 2006, we received notice from FERC confirming our status as a holding company as required under FERC regulations implementing PUHCA 2005 and granting exempt status similar to that held under PUHCA 1935.  As federal agencies continue to develop new rules to implement the Energy Policy Act, we expect additional impacts on us in the future.

Pension Reform:   In August 2006, President Bush signed the Pension Protection Act of 2006.  We are currently evaluating the Pension Protection Act of 2006, but we do not anticipate it will have a material impact on our results of operations or cash flows from operating activities.



ACCOUNTING DEVELOPMENTS

New Pronouncements:   See Note B ‐‐ Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements for information on new accounting pronouncements.



CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates.  The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs.  These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions.  In addition, the financial and operating environment also may have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments.

Regulatory Accounting:   We operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors.  Under SFAS 71, the actions of our regulators may allow us to defer costs that non‐regulated companies would expense.  The actions of our

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Pension and Other Post‐retirement Benefits:   Our reported costs of providing non‐contributory defined pension benefits (described in Note L ‐‐ Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.  Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets.  Changes made to the provisions of the plans may also impact current and future pension costs.  Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

In accordance with SFAS 87 and SFAS 158, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.  As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

The following chart reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage.  Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.



|Pension Plans
Actuarial Assumption                      |  | Impact on
Annual Cost
|------------------------------------------------------- |  | ---------------------
|                                                        |  |                      
|                                                        |  | (Millions of Dollars)
|                                                        |  |                      
|0.5% decrease in discount rate                          |  | $6.5                 
|0.5% decrease in expected rate of return on plan assets |  | $3.5                 



In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note L ‐‐ Benefits in the Notes to Consolidated Financial Statements).  We account for these plans in accordance with SFAS 106.  Our reported costs of providing these post‐retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends.  Changes made to the provisions of the plans may also impact current and future post‐retirement benefit costs.  OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the post‐retirement benefit obligation and post‐retirement costs.  Our OPEB plan assets are primarily made up of equity and fixed income investments.  Fluctuations in actual equity market returns, as well as changes in general interest rates, may result in increased or decreased other post‐retirement costs in future periods.  Similar to accounting for pension plans, our regulators have adopted SFAS 106 for rate making purposes.

---

The following chart reflects OPEB plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage.  Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.





|OPEB Plans
Actuarial Assumption                         |  | Impact on
Reported
Annual Cost
|------------------------------------------------------- |  | ------------------------------
|                                                       
|                                                        |  |                               
|                                                        |  | (Millions of Dollars)         
|                                                        |  |                               
|0.5% decrease in discount rate                          |  | $2.0                          
|0.5% decrease in health care cost trend rate            |  | ($2.7)                        
|0.5% decrease in expected rate of return on plan assets |  | $0.5                          



Unbilled Revenues:   We record utility operating revenues when energy is delivered to our customers.  However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated.  This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates.  Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate.  Total operating revenues during 2006 of $3,116.7 million included accrued revenues of $189.3 million as of December 31, 2006.

Asset Retirement Obligations:   We account for legal liabilities for asset retirements at fair value in the period in which they are incurred according to the provisions of SFAS 143 and FIN 47.  SFAS 143 applies primarily to decommissioning costs for Point Beach.  Using a discounted future cash flow methodology, our estimated nuclear ARO was approximately $325.6 million at December 31, 2006.  As it relates to our operations, FIN 47 applies primarily to asbestos removal costs.  At December 31, 2006, we recorded an obligation of $39.6 million related to asbestos.

Calculation of the nuclear decommissioning ARO is based upon projected decommissioning costs calculated by an independent decommissioning consulting firm, as well as several significant assumptions including the timing of future cash flows, future inflation rates and the discount rate applied to future cash flows.  Assuming the following changes in key assumptions and holding all other assumptions constant, we estimate that our nuclear ARO at December 31, 2006 would have changed by the following amounts:



|Change in Assumption          |  | Change in Liability  
|----------------------------- |  | ---------------------
|                              |  |                      
|                              |  | (Millions of Dollars)
|                              |  |                      
|1% increase in inflation rate |  | $106.7               
|1% decrease in inflation rate |  | ($79.8)              

We were unable to identify a viable market for or third party who would be willing to assume this liability.  Accordingly, we have used a market‐risk premium of zero when measuring our nuclear ARO.  We estimate that for each 1% increment that would be included as a market‐risk premium, our nuclear ARO would increase by approximately $3.3 million.

For additional information concerning SFAS 143 and our estimated nuclear ARO, see Note F ‐‐ Nuclear Operations and Note I ‐‐ Asset Retirement Obligations in the Notes to Consolidated Financial Statements.

---



|ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|-------- | ----------------------------------------------------------

See Factors Affecting Results, Liquidity and Capital Resources ‐‐ Market Risks and Other Significant Risks in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in this report for information concerning potential market risks to which we are exposed.

---



|ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                            |                                                |         |                
|--------------------------------------------------------------------------------------------------------------- | ---------------------------------------------- | ------- | ---------------
|                                                                                                                |                                                |         |                
|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                                               
|CONSOLIDATED INCOME STATEMENTS                                                                                  |                                               
|Year Ended December 31                                                                                          |                                               
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|Operating Revenues                                                                                              | $       3,116.7                                |         | $       2,938.0
|                                                                                                                |                                                |         |                
|Operating Expenses                                                                                              |                                                |         |                
|                                                                                                                | Fuel and purchased power                       | 798.0   |                
|                                                                                                                | Cost of gas sold                               | 431.6   |                
|                                                                                                                | Other operation and maintenance                | 1,074.5 |                
|                                                                                                                | Depreciation, decommissioning and amortization | 270.9   |                
|                                                                                                                | Property and revenue taxes                     | 85.8    |                
|                                                                                                                |                                                |         |                
|Total Operating Expenses                                                                                        | 2,660.8                                        |         | 2,460.7        
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|Operating Income                                                                                                | 455.9                                          |         | 477.3          
|                                                                                                                |                                                |         |                
|Equity in Earnings of Transmission Affiliate                                                                    | 33.9                                           |         | 30.4           
|Other Income, net                                                                                               | 42.9                                           |         | 28.4           
|Interest Expense                                                                                                | 87.0                                           |         | 85.8           
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|Income Before Income Taxes                                                                                      | 445.7                                          |         | 450.3          
|                                                                                                                |                                                |         |                
|Income Taxes                                                                                                    | 168.9                                          |         | 165.5          
|                                                                                                                |                                                |         |                
|Net Income                                                                                                      | 276.8                                          |         | 284.8          
|                                                                                                                |                                                |         |                
|Preferred Stock Dividend Requirement                                                                            | 1.2                                            |         | 1.2            
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|Earnings Available for Common Stockholder                                                                       | $         275.6                                |         | $         283.6
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|                                                                                                                |                                                |         |                
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



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|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                                            
|--------------------------------------------------------------------------------------------------------------- | -------------------------------------------
|CONSOLIDATED BALANCE SHEETS                                                                                     |                                            
|December 31                                                                                                     |                                            
|                                                                                                                |                                            
|ASSETS                                                                                                          |                                            
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                |                                            
|Property, Plant and Equipment                                                                                   |                                            
|                                                                                                                | Electric                                   
|                                                                                                                | Gas                                        
|                                                                                                                | Steam                                      
|                                                                                                                | Common                                     
|                                                                                                                | Other                                      
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                | Accumulated depreciation                   
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                | Construction work in progress              
|                                                                                                                | Leased facilities, net                     
|                                                                                                                | Nuclear fuel, net                          
|                                                                                                                |                                            
|Net Property, Plant and Equipment                                                                               | 5,291.0                                    
|                                                                                                                |                                            
|Investments                                                                                                     |                                            
|                                                                                                                | Nuclear decommissioning trust fund         
|                                                                                                                | Equity investment in transmission affiliate
|                                                                                                                | Other                                      
|                                                                                                                |                                            
|Total Investments                                                                                               | 1,083.2                                    
|                                                                                                                |                                            
|Current Assets                                                                                                  |                                            
|                                                                                                                | Cash and cash equivalents                  
|                                                                                                                | Accounts receivable, net of allowance for  
|                                                                                                                |                                            
|                                                                                                                | Accrued revenues                           
|                                                                                                                | Materials, supplies and inventories        
|                                                                                                                | Prepayments                                
|                                                                                                                | Other                                      
|                                                                                                                |                                            
|Total Current Assets                                                                                            | 928.4                                      
|                                                                                                                |                                            
|Deferred Charges and Other Assets                                                                               |                                            
|                                                                                                                | Regulatory assets                          
|                                                                                                                | Other                                      
|                                                                                                                |                                            
|Total Deferred Charges and Other Assets                                                                         | 955.2                                      
|                                                                                                                |                                            
|                                                                                                                |                                            
|Total Assets                                                                                                    | $        8,257.8                           
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                |                                            
|                                                                                                                |                                            
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



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|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                                                           
|--------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------
|CONSOLIDATED BALANCE SHEETS                                                                                     |                                                           
|December 31                                                                                                     |                                                           
|                                                                                                                |                                                           
|CAPITALIZATION AND LIABILITIES                                                                                  |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|Capitalization                                                                                                  |                                                           
|                                                                                                                | Common equity                                             
|                                                                                                                | Preferred stock                                           
|                                                                                                                | Long-term debt                                            
|                                                                                                                | Capital lease obligations                                 
|                                                                                                                |                                                           
|Total Capitalization                                                                                            | 4,430.6                                                   
|                                                                                                                |                                                           
|Current Liabilities                                                                                             |                                                           
|                                                                                                                | Long-term debt and capital lease obligations due currently
|                                                                                                                | Short-term debt                                           
|                                                                                                                | Accounts payable                                          
|                                                                                                                | Payroll and vacation accrued                              
|                                                                                                                | Accrued taxes                                             
|                                                                                                                | Accrued interest                                          
|                                                                                                                | Deferred income taxes - current                           
|                                                                                                                | Other                                                     
|                                                                                                                |                                                           
|Total Current Liabilities                                                                                       | 1,160.6                                                   
|                                                                                                                |                                                           
|Deferred Credits and Other Liabilities                                                                          |                                                           
|                                                                                                                | Regulatory liabilities                                    
|                                                                                                                | Deferred income taxes - long-term                         
|                                                                                                                | Asset retirement obligations                              
|                                                                                                                | Pension liability                                         
|                                                                                                                | Accumulated deferred investment tax credits               
|                                                                                                                | Other long-term liabilities                               
|                                                                                                                |                                                           
|Total Deferred Credits and Other Liabilities                                                                    | 2,666.6                                                   
|                                                                                                                |                                                           
|Commitments and Contingencies (Note Q)                                                                          | -                                                         
|                                                                                                                |                                                           
|Total Capitalization and Liabilities                                                                            | $     8,257.8                                             
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                                                               
|--------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------
|CONSOLIDATED STATEMENTS OF CASH FLOWS                                                                           |                                                               
|Year Ended December 31                                                                                          |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|Operating Activities                                                                                            |                                                               
|                                                                                                                | Net income                                                    
|                                                                                                                | Reconciliation to cash                                        
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|Cash Provided by Operating Activities                                                                           | 498.5                                                         
|                                                                                                                |                                                               
|Investing Activities                                                                                            |                                                               
|                                                                                                                | Capital expenditures                                          
|                                                                                                                | Investment in transmission affiliate                          
|                                                                                                                | Nuclear fuel                                                  
|                                                                                                                | Nuclear decommissioning funding                               
|                                                                                                                | Proceeds from investments within nuclear decommissioning trust
|                                                                                                                | Purchases of investments within nuclear decommissioning trust 
|                                                                                                                | Other                                                         
|                                                                                                                |                                                               
|Cash Used in Investing Activities                                                                               | (473.8)                                                       
|                                                                                                                |                                                               
|Financing Activities                                                                                            |                                                               
|                                                                                                                | Dividends paid on common stock                                
|                                                                                                                | Dividends paid on preferred stock                             
|                                                                                                                | Issuance of long-term debt                                    
|                                                                                                                | Retirement of long-term debt                                  
|                                                                                                                | Change in short-term debt                                     
|                                                                                                                | Capital contribution from parent                              
|                                                                                                                | Other, net                                                    
|                                                                                                                |                                                               
|Cash Used in Financing Activities                                                                               | (29.7)                                                        
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|Change in Cash and Cash Equivalents                                                                             | (5.0)                                                         
|                                                                                                                |                                                               
|Cash and Cash Equivalents at Beginning of Year                                                                  | 23.2                                                          
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|Cash and Cash Equivalents at End of Year                                                                        | $           18.2                                              
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|                                                                                                                |                                                               
|Supplemental Information - Cash Paid For                                                                        |                                                               
|                                                                                                                | Interest (net of amount capitalized)                          
|                                                                                                                | Income taxes (net of refunds)                                 
|                                                                                                                |                                                               
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. |                                                               

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|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                                                           
|--------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------
|CONSOLIDATED STATEMENTS OF CAPITALIZATION                                                                       |                                                           
|December 31                                                                                                     |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|Common Equity (See Consolidated Statements of Common Equity)                                                    |                                                           
|                                                                                                                | Common stock - $10 par value; authorized                  
|                                                                                                                |                                                           
|                                                                                                                | Other paid in capital                                     
|                                                                                                                | Retained earnings                                         
|                                                                                                                | Accumulated other comprehensive (loss)                    
|                                                                                                                |                                                           
|Total Common Equity                                                                                             |                                                           
|                                                                                                                |                                                           
|Preferred Stock                                                                                                 |                                                           
|                                                                                                                | Six Per Cent. Preferred Stock - $100 par value;           
|                                                                                                                |                                                           
|                                                                                                                | Serial preferred stock -                                  
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|Total Preferred Stock                                                                                           |                                                           
|                                                                                                                |                                                           
|Long-Term Debt                                                                                                  |                                                           
|                                                                                                                |                                                           
|                                                                                                                | Debentures (unsecured)                                    
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                | Notes (secured, nonrecourse)                              
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                | Notes (unsecured)                                         
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                | Obligations under capital leases                          
|                                                                                                                | Unamortized discount, net                                 
|                                                                                                                | Long-term debt and capital lease obligations due currently
|                                                                                                                |                                                           
|Total Long-Term Debt                                                                                            |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|Total Capitalization                                                                                            |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|                                                                                                                |                                                           
|(a)     Variable interest rate as of December 31, 2006.                                                         |                                                           
|(b)     Variable interest rate as of December 31, 2005.                                                         |                                                           
|                                                                                                                |                                                           
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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|WISCONSIN ELECTRIC POWER COMPANY                                                                                |                               
|--------------------------------------------------------------------------------------------------------------- | ------------------------------
|CONSOLIDATED STATEMENTS OF COMMON EQUITY                                                                        |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|Balance - December 31, 2003                                                                                     |                               
|                                                                                                                | Net income                    
|                                                                                                                | Other comprehensive income    
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Cash dividends                
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Tax benefit of exercised stock
|                                                                                                                |                               
|                                                                                                                |                               
|Balance - December 31, 2004                                                                                     |                               
|                                                                                                                | Net income                    
|                                                                                                                | Other comprehensive income    
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Cash dividends                
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Tax benefit of exercised stock
|                                                                                                                |                               
|                                                                                                                |                               
|Balance - December 31, 2005                                                                                     |                               
|                                                                                                                | Net income                    
|                                                                                                                | Other comprehensive income    
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Cash dividends                
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                | Cash contribution from Parent 
|                                                                                                                | Stock-based compensation      
|                                                                                                                | Tax benefit of exercised stock
|                                                                                                                |                               
|                                                                                                                | Adoption of SFAS 158          
|                                                                                                                |                               
|Balance - December 31, 2006                                                                                     |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|                                                                                                                |                               
|The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. |                               

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WISCONSIN ELECTRIC POWER COMPANY



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



A ‐‐ SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:

All significant intercompany transactions and balances have been eliminated from the consolidated financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Reclassifications:   We have reclassified certain prior year financial statement amounts to conform to their current year presentation.  These reclassifications had no effect on total assets or net income.

Revenues:   We recognize energy revenues on the accrual basis and include estimated amounts for services rendered but not billed.

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchase power costs.  The electric fuel rules in Wisconsin allow us to request rate increases if fuel and purchased power costs exceed bands established by the PSCW.  In a rate order issued in January 2006, the PSCW approved a plan to refund any over‐collected fuel on an annual basis for 2006.  For 2007, the band is plus or minus 2%.

Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs.  We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability.  The deferred balance is returned to or recovered from customers at intervals throughout the year.

Accounting for MISO Energy Transactions:   MISO implemented the MISO Midwest Market on April 1, 2005.  The MISO Midwest Market operates under both day‐ahead and real‐time markets.  We record energy transactions in the MISO on a net basis for each hour.

Other Income, net:   We recorded the following items in Other Income, net for the years ended December 31:



|                            |  |                       |  |       |  |      
|--------------------------- |  | --------------------- |  | ----- |  | -----
|Other Income, net           |  | 2006                  |  | 2005  |  | 2004 
|                            |  |                       |  |       |  |      
|                            |  | (Millions of Dollars)
|                            |  |                       |  |       |  |      
|Capitalized Carrying Costs  |  | $25.0                 |  | $20.4 |  | $12.7
|AFUDC ‐ Equity              |  | 14.5                  |  | 9.2   |  | 1.7  
|Donations and Contributions |  | (6.0)                 |  | (6.7) |  | (5.6)
|Gross Receipts Tax Recovery |  | 4.0                   |  | 2.6   |  | 1.5  
|Other, net                  |  | 5.4                   |  | 2.9   |  | (3.2)
|                            |  |                       |  |       |  |      
|Total Other Income, net     |  | $42.9                 |  | $28.4 |  | $7.1 
|                            |  |                       |  |       |  |      
|                            |  |                       |  |       |  |      
|                            |  |                       |  |       |  |      

---



Property and Depreciation:   We record property, plant and equipment at cost.  Cost includes material, labor, overheads and capitalized interest.  Utility property also includes AFUDC ‐ Equity.  Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense.  The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We include capitalized software costs associated with our regulated operations under the caption "Property, Plant and Equipment" on the Consolidated Balance Sheets.  As of December 31, 2006 and 2005, the net book value of our capitalized software totaled $17.7 million and $21.8 million, respectively.  The estimated useful life of our capitalized software is five years.

Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs.  Depreciation as a percent of average depreciable utility plant was 3.7% in 2006, 3.9% in 2005, and 4.0% in 2004.  Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note F).  The decline in depreciation as a percent of average depreciable utility plant was due to new depreciation rates approved by the PSCW, which became effective January 1, 2006.

For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight‐line rates over the estimated useful lives of the assets, or over the non‐cancellable lease term for leased equipment.

We collect in our rates amounts representing future removal costs for many assets that do not have an associated ARO.  W

Allowance For Funds Used During Construction:   AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC ‐ Debt) used during plant construction and a return on stockholders' capital (AFUDC ‐ Equity) used for construction purposes.  AFUDC ‐ Debt is recorded as a reduction of interest expense and AFUDC ‐ Equity is recorded in Other Income, net.

During 2006, we accrued AFUDC at a rate of 8.94%, as authorized by the PSCW.  During 2005 and 2004, the authorized rate was 10.18%.  We accrue AFUDC on all electric utility NOx, SO2 and particulates remediation projects.  Our rates were set to provide a full return on electric safety and reliability projects so AFUDC is not accrued on these projects.  We accrued AFUDC on 50% of the remaining electric, gas and steam projects in CWIP and rates were set assuming that 50% of the CWIP balances were included in rate base.

We recorded the following AFUDC for the years ended December 31:



|               |  | 2006                  |  | 2005 |  | 2004
|-------------- |  | --------------------- |  | ---- |  | ----
|               |  |                       |  |      |  |     
|               |  | (Millions of Dollars)
|               |  |                       |  |      |  |     
|AFUDC ‐ Debt   |  | $5.1                  |  | $4.6 |  | $0.9
|AFUDC ‐ Equity |  | $14.5                 |  | $9.2 |  | $1.7



Materials, Supplies and Inventories:   Our inventory at December 31 consists of:



|Materials, Supplies and Inventories |  | 2006                  |  | 2005  
|----------------------------------- |  | --------------------- |  | ------
|                                    |  |                       |  |       
|                                    |  | (Millions of Dollars)
|                                    |  |                       |  |       
|Fossil Fuel                         |  | $119.7                |  | $90.4 
|Materials and Supplies              |  | 100.6                 |  | 89.3  
|Natural Gas in Storage              |  | 92.7                  |  | 117.8 
|                                    |  |                       |  |       
|Total                               |  | $313.0                |  | $297.5
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       

Substantially all fossil fuel, materials and supplies and natural gas in storage inventories are recorded using the weighted‐average method of accounting.

---

Regulatory Accounting:   We account for our regulated operations in accordance with SFAS 71.  This statement sets forth the application of GAAP to those companies whose rates are determined by an independent third‐party regulator.  The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise.  When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates.  We defer all of our regulatory assets pursuant to specific orders or by a generic order issued by our primary regulator.  Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).  We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years.  For further information, see Note C.

Derivative Financial Instruments:   We have derivative physical and financial instruments as defined by SFAS 133 which we report at fair value.  However, our use of financial instruments is limited.  For further information, see Note J.

Cash and Cash Equivalents:   Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

We have nuclear decommissioning trusts that hold investments in debt and equity securities.  All assets within the nuclear decommissioning trusts are restricted to nuclear decommissioning activities as set forth by regulations promulgated by the IRS and by the PSCW.  The accompanying Consolidated Statements of Cash Flows include proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts.

Margin Accounts:   Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.

Restrictions:   Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances.  In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.  We do not believe that these restrictions will materially affect our operations.  For further information, see Note N.

Asset Retirement Obligations:   We adopted SFAS 143 effective January 1, 2003.  We adopted FIN 47 effective December 31, 2005.  FIN 47 defines the term conditional ARO as used in SFAS 143.  As defined in FIN 47, a conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.  Consistent with SFAS 143, we record a liability at fair value for a legal ARO in the period in which it is incurred.  When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long‐lived asset.  We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset.  At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss.  As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs under SFAS 143.  For further information, see Note I.

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method.  As of December 31, 2006 and 2005, we had a total ownership interest of approximately 25.8% and 29.4%, in ATC.  We are represented by one out of ten ATC board members, each of whom has one vote.  Due to the voting requirements, no individual member has more than 10% of the voting control.  For further information regarding such investments, see Note P.

Nuclear Fuel Amortization:   We lease our nuclear fuel and amortize the fuel inventory to fuel expense as the power is generated, generally over a period of 60 months.

Income Taxes:   We follow the liability method in accounting for income taxes as prescribed by SFAS 109.  SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax

---

Tax credits associated with regulated operations are deferred and amortized over the life of the assets.  We are included in Wisconsin Energy's consolidated Federal income tax return.  Wisconsin Energy allocates Federal tax expense or credits to us based on our separate tax computation.

Investment tax credits related to regulated utility assets are recorded as a deferred credit on the balance sheet and amortized to income over the applicable service lives of related properties in accordance with regulatory treatment.  Historical rehabilitation credits are reported in income in the year claimed.

Wisconsin Energy allocates the tax benefit of stock options exercised to us to the extent the option holder's payroll cost was incurred by us.  We record the allocated tax benefit as an addition to paid in capital.

We recognize interest and penalties accrued related to unrecognized tax benefits in Income Taxes in our Consolidated Income Statements, as well as Regulatory Assets or Regulatory Liabilities in our Consolidated Balance Sheets.

We collect sales and use taxes from our customers and remit these taxes to governmental authorities.  These taxes are recorded in our Consolidated Income Statements on a net basis.

Stock Options:   Employees of Wisconsin Electric participate in the Wisconsin Energy stock‐based compensation plan.  The amounts reported represent the allocated costs related to options held by our employees.  For more information on the plan, see Note N.

Effective January 1, 2006, Wisconsin Energy adopted SFAS 123R, using the modified prospective method.  Wisconsin Energy uses a binomial pricing model to estimate the fair value of stock options granted subsequent to December 31, 2005.  Prior to January 1, 2006, Wisconsin Energy accounted for share based compensation under APB 25, Accounting for Stock Issued to Employees, and we disclosed the pro forma impact of share based compensation expense under SFAS 123.  Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than ten years from the grant date.  Accordingly, no compensation expense was recognized in connection with option grants.  All options granted subsequent to December 31, 2004 vest on a cliff‐basis after a three year period.  Prior to January 1, 2006, we reported benefits of tax deductions in excess of recognized compensation costs as operating cash flows.  SFAS 123R requires that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow.  For further discussion of this new standard and the impacts to our Consolidated Financial Statements, see Note N.

Wisconsin Energy previously adopted the disclosure provisions of SFAS 123 as amended by SFAS 148.  The fair value of each Wisconsin Energy option at date of grant for 2006 was calculated using a binomial option pricing model.  For 2005 and 2004, the fair value of options at the date of grant was estimated using the Black‐Scholes option‐pricing model with the following weighted average assumptions:



|                                   |  | Binomial      |  | Black‐Scholes
|---------------------------------- |  | ------------- |  | -------------
|                                   |  | 2006          |  | 2005         
|                                   |  |               |  |              
|Risk free interest rate            |  | 4.3% ‐ 4.4%   |  | 4.4%         
|Dividend yield                     |  | 2.4%          |  | 2.5%         
|Expected volatility                |  | 17.0% ‐ 20.0% |  | 19.0%        
|Expected life (years)              |  | 6.3           |  | 10.0         
|Pro forma weighted average fair    |  |               |  |              
|value of our stock options granted |  | $7.55         |  | $8.32        

---

As described more fully in the following table, had we expensed the 2005 and 2004 grants for stock‐based compensation plans under SFAS 123, our net income would have been reduced to the pro forma amounts set forth in the table below.  In 2004, the pro forma expense increased, in part, due to the effect of accelerating the vesting of Wisconsin Energy stock options held by our employees.  For further information regarding equity based compensation see Note N.



|                                                                                                                                                           |  | 2005                  |  | 2004  
|---------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------- |  | ------
|                                                                                                                                                           |  |                       |  |       
|                                                                                                                                                           |  | (Millions of Dollars)
|                                                                                                                                                           |  |                       |  |       
|Net Income ‐ as reported                                                                                                                                   |  | $283.6                |  | $248.7
|Add: Stock‐based employee
     compensation expense included
     in reported net income, net of related
     tax effects                                  |  | 1.7                   |  | 2.0   
|Deduct: Total stock‐based employee
     compensation expense determined
     under fair value based method for all
     awards, net of related tax effects |  | 3.0                   |  | 20.2  
|                                                                                                                                                           |  |                       |  |       
|Net Income ‐ Pro forma                                                                                                                                     |  | $282.3                |  | $230.5
|                                                                                                                                                           |  |                       |  |       
|                                                                                                                                                           |  |                       |  |       
|                                                                                                                                                           |  |                       |  |       





B ‐‐ RECENT ACCOUNTING PRONOUNCEMENTS

Share Based Compensation:   In December 2004, the FASB issued SFAS 123R, which amended SFAS 123.  In March 2005, the SEC issued SAB 107 regarding the SEC's interpretation of SFAS 123R and the valuation of share‐based payment for public companies.  This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement.  Wisconsin Energy adopted SFAS 123R and SAB 107 effective January 1, 2006 using the modified prospective method.  For additional information, see Note N.

Implicit Variable Interests:   In April 2006, the FASB issued FSP FIN 46R‐6.  FSP FIN 46R‐6 addresses the requirement to determine the variability to be considered in applying FIN 46R‐6 based on an analysis of the design of the entity.  As required, we adopted FSP FIN 46R‐6 effective July 1, 2006 for any new arrangements entered into after the effective date.  For further information, see Note D.

Uncertainty in Income Taxes:   In July 2006, the FASB issued FIN 48, an interpretation of SFAS 109.  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the enterprise's financial statements in accordance with SFAS 109.  We adopted FIN 48 effective January 1, 2007.  For further information, see Note E.

Fair Value Measurements:   In September 2006, the FASB issued SFAS 157.  SFAS 157 provides guidance for using fair value to measure assets and liabilities.  SFAS 157 defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements.  SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007.  We are currently evaluating the provisions of SFAS 157 and we expect to adopt SFAS 157 on January 1, 2008.

Pension and Other Post‐retirement Plans:   In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, 88, 106 and 132R.  SFAS 158 requires recognition of the overfunded or underfunded status of a defined benefit post‐retirement plan as an asset or liability on the balance sheet and recognition of changes in that funded status in the year in which the changes occur through comprehensive income.  SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year end balance sheet.  We adopted SFAS 158 as of December 31, 2006.  For further information, see Note L.

Financial Statement Errors:   In September 2006, the SEC staff issued SAB 108.  SAB 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements.  SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements.  We adopted the provisions of SAB 108 effective December 31, 2006.  The adoption of SAB 108 did not have any financial impact on our consolidated financial statements.

---

C ‐‐ REGULATORY ASSETS AND LIABILITIES

We account for our regulated operations in accordance with SFAS 71.

Our primary regulator considers our regulatory assets and liabilities in two categories, escrowed and deferred.  In escrow accounting we expense amounts that are included in rates.  If actual costs exceed, or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates.  Under deferred cost accounting, we defer amounts to our balance sheet based upon specific orders or correspondence with our primary regulator.  These deferred costs will be considered in future rate setting proceedings.  As of December 31, 2006, we had approximately $30.0 million of net regulatory assets that were not earning a return.

Our regulatory assets and liabilities as of December 31 consist of:



|                                                          |  | 2006                  |  | 2005    
|--------------------------------------------------------- |  | --------------------- |  | --------
|                                                          |  |                       |  |         
|                                                          |  | (Millions of Dollars)
|Regulatory Assets                                         |  |                       |  |         
|Deferred unrecognized pension costs  (see Note L)         |  | $236.3                |  | $240.7  
|Escrowed electric transmission costs                      |  | 192.2                 |  | 169.4   
|Deferred income tax related                               |  | 95.2                  |  | 93.5    
|Deferred plant related ‐‐ capital leases (see Note G)     |  | 88.9                  |  | 72.4    
|Deferred fuel related costs                               |  | 79.1                  |  | 72.8    
|Deferred environmental costs                              |  | 42.4                  |  | 43.9    
|Escrowed unrecovered plant costs                          |  | 31.6                  |  | 56.5    
|Other, net                                                |  | 93.8                  |  | 73.3    
|                                                          |  |                       |  |         
|Total long‐term regulatory assets                         |  | $859.5                |  | $822.5  
|                                                          |  |                       |  |         
|Regulatory Liabilities                                    |  |                       |  |         
|Deferred asset retirement obligations (see Notes F and I) |  | $537.1                |  | $475.3  
|Deferred cost of removal obligations (see Notes F and I)  |  | 430.5                 |  | 414.1   
|Deferred income tax related                               |  | 85.6                  |  | 91.6    
|Other, net                                                |  | 89.1                  |  | 70.9    
|                                                          |  |                       |  |         
|Total long‐term regulatory liabilities                    |  | $1,142.3              |  | $1,051.9
|                                                          |  |                       |  |         
|Net long‐term regulatory liabilities                      |  | $282.8                |  | $229.4  
|                                                          |  |                       |  |         
|                                                          |  |                       |  |         
|                                                          |  |                       |  |         

As of December 31, 2005, we recorded a minimum pension liability to reflect the funded status of our pension plans (see Note L).  Under SFAS 158, which Wisconsin Energy adopted effective December 31, 2006, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

We record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A).

In October 2002, the PSCW issued an order authorizing us to implement a surcharge for recovery of annual electric transmission costs projected through 2005.  In addition, the PSCW order authorized escrow accounting treatment for transmission costs.

As of December 31, 2006, we have deferred $79.1 million of fuel related costs.  The majority of these deferred costs were incurred in 2005 as a result of an extended outage at Point Beach, increased costs associated with reduced coal deliveries due to a railroad transportation problem and increased costs associated with the MISO Midwest Market.

Consistent with a generic order from and past rate‐making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites.  As of December 31, 2006, we have recorded $42.4 million of environmental costs associated with manufactured gas plant sites as a regulatory asset,

---

As part of Wisconsin Energy's PTF strategy, the PSCW approved the retirement and removal of the Port Washington Power Plant coal units to make way for construction of gas‐fired facilities.  In a September 27, 2003 order, the PSCW authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account.  The escrowed unrecovered plant costs totaled $31.6 million at December 31, 2006.





D ‐‐ VARIABLE INTEREST ENTITIES

Under FIN 46 and FIN 46R, the primary beneficiary of a variable interest entity must consolidate the related assets and liabilities.

We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis.  After making an exhaustive effort, we concluded that for three of these agreements, we are unable to obtain the information necessary to determine whether these entities are variable interest entities.  Pursuant to the terms of two of the three agreements, we deliver fuel to the entity's facilities and receive electric power.  We pay the entity a "toll" to convert our fuel into the electric energy.  The output of the facility is available for us to dispatch during the term of the respective agreement.  In the other agreement, we have rights to the firm capacity of the entity's facility.  We have approximately $603.0 million of required payments over the remaining term of these three agreements, which expire over the next 16 years.  We believe the required payments will continue to be recoverable in rates.  We account for one of these agreements as a capital lease.

In April 2006, the FASB issued FSP FIN 46R‐6.  As required, we adopted FSP FIN 46R‐6 effective July 1, 2006 for any new arrangements entered into after the effective date.  Although the adoption of FSP FIN 46R‐6 did not have a material financial impact in the current period, we currently are unable to determine the potential impact in future periods.





E ‐‐ INCOME TAXES

The following table is a summary of income tax expense for each of the years ended December 31:



|Income Taxes               |  | 2006                  |  | 2005   |  | 2004  
|-------------------------- |  | --------------------- |  | ------ |  | ------
|                           |  |                       |  |        |  |       
|                           |  | (Millions of Dollars)
|                           |  |                       |  |        |  |       
|Current tax expense        |  | $228.2                |  | $145.6 |  | $16.4 
|Deferred income taxes, net |  | (55.4)                |  | 24.1   |  | 141.2 
|Investment tax credit, net |  | (3.9)                 |  | (4.2)  |  | (4.4) 
|                           |  |                       |  |        |  |       
|Total Income Tax Expense   |  | $168.9                |  | $165.5 |  | $153.2
|                           |  |                       |  |        |  |       
|                           |  |                       |  |        |  |       
|                           |  |                       |  |        |  |       

---

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:



|                               |  | 2006                  |  | 2005               |  | 2004  
|------------------------------ |  | --------------------- |  | ------------------ |  | ------
|                               |  |                       |  |                    |  |       
|Income Tax Expense             |  | Amount                |  | Effective
Tax Rate |  | Amount
|                               |  |                       |  |                    |  |       
|                               |  | (Millions of Dollars)
|                               |  |                       |  |                    |  |       
|Expected tax at                |  |                       |  |                    |  |       
|statutory federal tax rates    |  | $155.6                |  | 35.0%              |  | $157.2
|State income taxes             |  |                       |  |                    |  |       
|net of federal tax benefit     |  | 22.6                  |  | 5.1%               |  | 20.9  
|Investment tax credit restored |  | (3.9)                 |  | (0.9%)             |  | (4.2) 
|Other, net                     |  | (5.4)                 |  | (1.2%)             |  | (8.4) 
|                               |  |                       |  |                    |  |       
|Total Income Tax Expense       |  | $168.9                |  | 38.0%              |  | $165.5
|                               |  |                       |  |                    |  |       
|                               |  |                       |  |                    |  |       
|                               |  |                       |  |                    |  |       

---



The components of SFAS 109 deferred income taxes classified as net current liabilities and net long‐term liabilities at December 31 are as follows:



|                                           |  | 2006                  |  | 2005     | 
|------------------------------------------ |  | --------------------- |  | -------- | 
|                                           |  |                       |  |          | 
|                                           |  | (Millions of Dollars) | 
|Deferred Tax Assets                        |  |                       |  |          | 
|                                           |  |                       |  |          | 
|Current                                    |  |                       |  |          | 
|Employee benefits and compensation         |  | $10.7                 |  | $10.2    | 
|Recoverable gas costs                      |  | 7.5                   |  | 1.3      | 
|Other                                      |  | 2.1                   |  | 5.7      | 
|                                           |  |                       |  |          | 
|Total Current Deferred Tax Assets          |  | $20.3                 |  | $17.2    | 
|                                           |  |                       |  |          | 
|Non‐current                                |  |                       |  |          | 
|Decommissioning trust                      |  | 98.1                  |  | 85.8     | 
|Employee benefits and compensation         |  | 95.8                  |  | 99.7     | 
|Construction advances                      |  | 84.8                  |  | 71.6     | 
|Deferred revenues                          |  | 84.2                  |  | 28.3     | 
|Emission allowances                        |  | 19.0                  |  | 18.4     | 
|Property‐related                           |  | 7.2                   |  | 7.2      | 
|Other                                      |  | 9.2                   |  | 15.2     | 
|                                           |  |                       |  |          | 
|Total Non‐current Deferred Tax Assets      |  | 398.3                 |  | 326.2    | 
|                                           |  |                       |  |          | 
|Total Deferred Tax Assets                  |  | $418.6                |  | $343.4   | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|Deferred Tax Liabilities                   |  |                       |  |          | 
|                                           |  |                       |  |          | 
|Current                                    |  |                       |  |          | 
|Prepaid items                              |  | $35.1                 |  | $32.3    | 
|Uncollectible account expense              |  | 9.1                   |  | 7.3      | 
|                                           |  |                       |  |          | 
|Total Current Deferred Tax Liabilities     |  | $44.2                 |  | $39.6    | 
|                                           |  |                       |  |          | 
|Non‐current                                |  |                       |  |          | 
|Property‐related                           |  | 760.6                 |  | 746.3    | 
|Deferred transmission costs                |  | 76.5                  |  | 64.6     | 
|Investment in transmission affiliate       |  | 38.9                  |  | 35.4     | 
|Other                                      |  | 32.4                  |  | 33.1     | 
|                                           |  |                       |  |          | 
|Total Non‐current Deferred Tax Liabilities |  | 908.4                 |  | 879.4    | 
|                                           |  |                       |  |          | 
|Total Deferred Tax Liabilities             |  | $952.6                |  | $919.0   | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|                                           |  |                       |  |          | 
|Consolidated Balance Sheet Presentation    |  | 2006                  |  | 2005     | 
|                                           |  |                       |  |          | 
|Current Deferred Tax Asset (Liability)     |  | ($23.9)               |  | ($22.4)  | 
|Non‐current Deferred Tax Asset (Liability) |  | ($510.1)              |  | ($553.2) | 

Consistent with ratemaking treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.

In July 2006, the FASB issued FIN 48, an interpretation of SFAS 109.  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the enterprise's financial statements in accordance with SFAS 109.  FIN 48 provides clarification on the accounting for income taxes by setting forth a minimum recognition threshold an uncertain tax position is required to meet before being recognized in the financial statements.  FIN 48 also provides guidance on de‐recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.  FIN 48 is effective for fiscal years beginning after December 15, 2006.  We adopted FIN 48 effective January 1, 2007.  As a result of the adoption of FIN 48, we estimate that the cumulative effect on retained earnings is immaterial.

---

F ‐‐ NUCLEAR OPERATIONS

Point Beach Nuclear Plant:   We own two 518 MW electric generating units at Point Beach in Two Rivers, Wisconsin.  NMC operates the units on our behalf.  The units were placed in service in the early 1970's and the original operating licenses were effective through 2010 and 2013.  In December 2005, the NRC renewed the operating licenses through October 2030 for Unit 1 and March 2033 for Unit 2.

Proposed Sale of Point Beach:   In December 2006, we announced that we signed a definitive agreement with an affiliate of FPL to sell Point Beach for approximately $998 million, subject to closing price adjustments.  Under the terms of the sale, the buyer would assume the obligation to decommission the plant, and we would transfer assets in a qualified trust for decommissioning.  We would retain assets in a non‐qualified decommissioning trust.  We also entered into a long‐term power purchase agreement to purchase all of the existing capacity and energy of the plant, which will become effective upon closing of the sale.  We will have the unilateral option, subject to PSCW direction, to select a term for the power purchase agreement of either (i) an estimated 23 years for Unit 1 and 26 years for Unit 2, or (ii) 16 years for Unit 1 and 17 years for Unit 2.  The sale of the plant and the long‐term power purchase agreement are subject to review and approval by various regulatory agencies including the NRC, PSCW, MPSC and FERC.  We anticipate closing the sale during the third quarter of 2007.  We have submitted a request to the PSCW to defer any gain (net of transaction related costs) as a regulatory liability that would be applied to the benefit of our customers in future rate proceedings.

Nuclear Insurance:   The Price‐Anderson Act currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $10.8 billion, of which $300 million is covered by liability insurance purchased from private sources.  The remaining $10.5 billion is covered by an industry retrospective loss sharing plan whereby, in the event of a nuclear incident resulting in damages exceeding the private insurance coverage, each owner of a nuclear plant would be assessed a deferred premium of up to $100.6 million per reactor with a limit of $15 million per reactor within one calendar year.  We have two reactors.  We are obligated to pay our proportionate share of any such assessment as long as we own Point Beach.

Through our membership in NEIL, we carry decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 billion at Point Beach.  Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL.  Our maximum retrospective liability under the above policies is $17.8 million.

We also maintain insurance with NEIL through which we can recover up to $3.5 million per week, subject to a total limit of $490 million, during any prolonged outage at Point Beach caused by accidental property damage.  Our maximum retrospective liability under this policy is $9.8 million.

It should not be assumed that, in the event of a major nuclear incident, any insurance or statutory limitation of liability would protect us from material adverse impact.

Nuclear Decommissioning:   We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts.  Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates.  Decommissioning funding was $17.6 million for each of the years ended 2006, 2005 and 2004.  As of December 31, 2006, our non‐qualified investments were $303.7 million and our qualified investments were $577.9 million.  We had the following investments in nuclear decommissioning trusts, stated at fair value as of December 31, 2006 and 2005.



|                              |  | 2006                  |  | 2005  
|----------------------------- |  | --------------------- |  | ------
|                              |  |                       |  |       
|                              |  | (Millions of Dollars)
|                              |  |                      
|Funding and Realized Earnings |  | $607.2                |  | $566.6
|Net Unrealized Gains          |  | 274.4                 |  | 215.5 
|                              |  |                       |  |       
|Total Investments             |  | $881.6                |  | $782.1
|                              |  |                       |  |       
|                              |  |                       |  |       
|                              |  |                       |  |       

As of December 31, 2006, approximately 66.5% of the trust funds were invested in equity securities and 33.5% were invested in debt securities.  In accordance with SFAS 115, our debt and equity security investments in the trusts are classified as available for sale.  Gains and losses on the fund are determined on the basis of specific identification;

---



|                  |  | 2006                  |  | 2005 
|----------------- |  | --------------------- |  | -----
|                  |  |                       |  |      
|                  |  | (Millions of Dollars)
|                  |  |                       |  |      
|Realized Gains    |  | $21.2                 |  | $19.1
|Realized (Losses) |  | (10.6)                |  | (9.1)
|                  |  |                       |  |      
|Net Realized Gain |  | $10.6                 |  | $10.0
|                  |  |                       |  |      
|                  |  |                       |  |      
|                  |  |                       |  |      



Total gains and total losses by security type for the years ended December 31, 2006 and 2005 were as follows:



|December 31, 2006 |  | Total Gains |  | Total (Losses) |  | Net Gain (Loss)
|----------------- |  | ----------- |  | -------------- |  | ---------------
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                
|Debt              |  | $1.4        |  | ($5.2)         |  | ($3.8)         
|Equity            |  | 296.5       |  | (7.7)          |  | 288.8          
|                  |  |             |  |                |  |                
|Total             |  | $297.9      |  | ($12.9)        |  | $285.0         
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                



|December 31, 2005 |  | Total Gains |  | Total (Losses) |  | Net Gain (Loss)
|----------------- |  | ----------- |  | -------------- |  | ---------------
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                
|Debt              |  | $2.1        |  | ($5.0)         |  | ($2.9)         
|Equity            |  | 236.5       |  | (8.1)          |  | 228.4          
|                  |  |             |  |                |  |                
|Total             |  | $238.6      |  | ($13.1)        |  | $225.5         
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                
|                  |  |             |  |                |  |                



The contractual maturities of debt securities at December 31, 2006 are as follows: $14.8 million in 2007; $52.0 million in 2008‐2011; $97.9 million in 2012‐2016; and $125.2 million thereafter.

The PSCW requires us to perform periodic Decommissioning Cost Studies to evaluate the funded status of our nuclear decommissioning trusts as compared with the estimated costs to perform the decommissioning work.  In June 2005, we filed a new Decommissioning Cost Study with the PSCW.  The study was performed by an outside consultant and it included several assumptions as to the timing and scope of the decommissioning work.  This study estimated that the cost to decommission the plant would be $712.5 million in 2004 dollars.  A prior study had estimated the cost to be $1.1 billion in 2003 dollars.  The reduction in the estimated costs to decommission the plant was driven by several factors including the timing and the scope of the work to be performed.

The June 2005 Decommissioning Cost Study was also used to estimate our ARO for nuclear decommissioning.  We record an ARO for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our plants.  Under SFAS 143, certain costs included in the June 2005 Decommissioning Cost Study that related to fuel management and non‐nuclear demolition were excluded from the ARO calculation.  Using the June 2005 study, our estimated costs for decommissioning, following SFAS 143, were $473.2 million.  Our ARO for nuclear decommissioning as of December 31, 2006 was $325.6 million.

We recover decommissioning costs in our regulated rates.  We have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and cumulative investment gains (our nuclear decommissioning trust investments) in comparison to the ARO for nuclear decommissioning that is calculated under SFAS 143.  For further information on AROs, see Note I.

The ultimate timing and amount of future cash flows associated with nuclear decommissioning is dependent upon many significant variables including the scope of work involved, the ability to relicense the plants in the future, future inflation rates and discount rates.  Because of our announced agreement to sell Point Beach to an affiliate of FPL, we do not expect to remain obligated to decommission Point Beach if the sale is consummated.  However, if

---

Decontamination and Decommissioning Fund:   The Energy Policy Act of 1992 established a D&D Fund for the DOE's nuclear fuel enrichment facilities.  Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services.  In October 2006, a final payment was made to the DOE.  As a result, a liability no longer exists for this fund.  The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates through September 2007.





G ‐‐ LONG‐TERM DEBT

Debentures and Notes:   As of December 31, 2006, the maturities and sinking fund requirements of our long‐term debt outstanding (excluding obligations under capital leases) were as follows:



|           |  | (Millions of Dollars)
|---------- |  | ---------------------
|           |  |                      
|2007       |  | $250.0               
|2008       |  | ‐                    
|2009       |  | 0.1                  
|2010       |  | 0.1                  
|2011       |  | ‐                    
|Thereafter |  | 1,351.4              
|           |  |                      
|Total      |  | $1,601.6             
|           |  |                      
|           |  |                      
|           |  |                      



We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.

In November 2006, we issued $300 million of 5.70% Debentures due December 1, 2036.  The securities were issued under an existing $665 million shelf registration statement filed with the SEC.  The net proceeds from the sale were used to retire our $200 million of 6‐5/8% Debentures due November 15, 2006 at their scheduled maturity and to repay outstanding commercial paper incurred for working capital requirements.

Capital Leases:   In 1997, we entered into a 25‐year power purchase contract with an unaffiliated independent power producer.  The contract, for 236 MW of firm capacity from a gas‐fired cogeneration facility, includes no minimum energy requirements.  When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire.  We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities.  We are amortizing the leased facility on a straight‐line basis over the original 25‐year term of the contract.

We treat the long‐term power purchase contract as an operating lease for rate‐making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements.  We paid a total of $26.1 million, $25.2 million and $24.3 million in minimum lease payments during 2006, 2005, and 2004, respectively.  We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets ‐ Deferred plant related ‐ capital leases in Note C).  Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 at which time the regulatory asset will be reduced to zero over the remaining life of the contract.  The total obligation under the capital lease was $159.4 million at December 31, 2006 and will decrease to zero over the remaining life of the contract.

In July 2005, the first 545‐MW natural gas‐fired generation unit was placed in service at the PWGS.  We are leasing this unit from We Power under a PSCW approved lease.  Pursuant to SFAS 13, Accounting for Leases, we are accounting for this lease as a capital lease and have recorded the leased plant and corresponding obligation under the

---

This lease is treated as an operating lease for rate‐making purposes.  We record the lease payments as rent expense in other operation and maintenance in the Consolidated Income Statement.  The lease payments are expected to be recovered through our rates.  The recoverability of the lease payments is supported by the 2001 lease generation law.  We paid a total of $47.8 million and $21.9 million in minimum lease payments during 2006 and 2005, respectively.  We are recording a deferred regulatory asset for the difference between the lease payments and the sum of imputed interest cost and amortization costs calculated under capital lease accounting (see Regulatory Assets ‐ Deferred plant related ‐ capital leases in Note C).  Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $125.1 million in the year 2021 at which time the regulatory asset will be reduced to zero over the remaining life of the contract.  The total obligation under the capital lease was $333.5 million at December 31, 2006 and will decrease to zero over the remaining life of the contract.

We also have a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease.  We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months.  Lease payments include charges for the cost of fuel burned, financing costs and management fees.  In the event that we or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from us.  Under the lease terms, we are in effect the ultimate guarantor of the Trust's commercial paper and line of credit borrowings that finance the investment in nuclear fuel.  We recorded $4.2 million, $1.7 million and $1.4 million of interest expense on the nuclear fuel lease in fuel expense during 2006, 2005 and 2004, respectively.

Following is a summary of our capitalized leased facilities and nuclear fuel at December 31.



|Capital Lease Assets                |  | 2006                  |  | 2005  
|----------------------------------- |  | --------------------- |  | ------
|                                    |  |                       |  |       
|                                    |  | (Millions of Dollars)
|Leased Facilities                   |  |                       |  |       
|Long‐term purchase power commitment |  | $140.3                |  | $140.3
|Accumulated amortization            |  | (52.8)                |  | (47.1)
|                                    |  |                       |  |       
|Total Leased Facilities             |  | $87.5                 |  | $93.2 
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|PWGS Unit 1                         |  |                       |  |       
|Under capital lease                 |  | $336.0                |  | $335.5
|Accumulated amortization            |  | (19.5)                |  | (6.1) 
|                                    |  |                       |  |       
|Total PWGS Unit 1                   |  | $316.5                |  | $329.4
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|Nuclear Fuel                        |  |                       |  |       
|Under capital lease                 |  | $136.0                |  | $125.6
|Accumulated amortization            |  | (70.4)                |  | (60.2)
|In process/stock                    |  | 65.3                  |  | 46.6  
|                                    |  |                       |  |       
|Total Nuclear Fuel                  |  | $130.9                |  | $112.0
|                                    |  |                       |  |       
|                                    |  |                       |  |       
|                                    |  |                       |  |       

---



Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2006 are as follows:



|Capital Lease Obligations        |  | Purchase
Power
Commitment |  | PWGS 1  |  | Nuclear
Fuel Lease |  | Total    
|-------------------------------- |  | ------------------------- |  | ------- |  | ------------------ |  | ---------
|                                 |  |                           |  |         |  |                    |  |          
|                                 |  | (Millions of Dollars)    
|                                 |  |                           |  |         |  |                    |  |          
|2007                             |  | $32.4                     |  | $48.0   |  | $29.2              |  | $109.6   
|2008                             |  | 33.6                      |  | 48.0    |  | 24.6               |  | 106.2    
|2009                             |  | 34.9                      |  | 48.0    |  | 15.4               |  | 98.3     
|2010                             |  | 36.2                      |  | 48.0    |  | 5.9                |  | 90.1     
|2011                             |  | 37.5                      |  | 48.0    |  | 2.9                |  | 88.4     
|Thereafter                       |  | 295.3                     |  | 889.8   |  | ‐                  |  | 1,185.1  
|                                 |  |                           |  |         |  |                    |  |          
|Total Minimum Lease Payments     |  | 469.9                     |  | 1,129.8 |  | 78.0               |  | 1,677.7  
|Less:  Estimated Executory Costs |  | (103.8)                   |  | ‐       |  | ‐                  |  | (103.8)  
|                                 |  |                           |  |         |  |                    |  |          
|Net Minimum Lease Payments       |  | 366.1                     |  | 1,129.8 |  | 78.0               |  | 1,573.9  
|Less:  Interest                  |  | (206.7)                   |  | (796.3) |  | (6.0)              |  | (1,009.0)
|                                 |  |                           |  |         |  |                    |  |          
|Present Value of Net             |  |                           |  |         |  |                    |  |          
|Minimum Lease Payments           |  | 159.4                     |  | 333.5   |  | 72.0               |  | 564.9    
|Less:  Due Currently             |  | (2.0)                     |  | (2.0)   |  | (26.4)             |  | (30.4)   
|                                 |  |                           |  |         |  |                    |  |          
|                                 |  | $157.4                    |  | $331.5  |  | $45.6              |  | $534.5   
|                                 |  |                           |  |         |  |                    |  |          
|                                 |  |                           |  |         |  |                    |  |          
|                                 |  |                           |  |         |  |                    |  |          





H ‐‐ SHORT‐TERM DEBT

Short‐term notes payable balances and their corresponding weighted‐average interest rates as of December 31 consist of:



|                      |  | 2006                                          |  | 2005         
|--------------------- |  | --------------------------------------------- |  | -------------
|                      |  |                                               |  |              
|Short‐Term Debt       |  | Balance                                       |  | Interest
Rate
|                      |  |                                               |  |              
|                      |  | (Millions of Dollars, except for percentages)
|                      |  |                                               |  |              
|Commercial Paper      |  | $274.1                                        |  | 5.37%        
|Other                 |  | 30.1                                          |  | 6.36%        
|                      |  |                                               |  |              
|Total Short‐Term Debt |  | $304.2                                        |  | 5.47%        
|                      |  |                                               |  |              
|                      |  |                                               |  |              
|                      |  |                                               |  |              

On December 31, 2006, we had approximately $485.9 million of available unused lines under our bank back‐up credit facility.  Our bank back‐up credit facility expires in March 2011.

The following information relates to commercial paper outstanding for the years ended December 31, 2006 and 2005:



|                                     |  | 2006                                          |  | 2005  
|------------------------------------ |  | --------------------------------------------- |  | ------
|                                     |  |                                               |  |       
|                                     |  | (Millions of Dollars, except for percentages)
|                                     |  |                                               |  |       
|Maximum Commercial Paper Outstanding |  | $369.9                                        |  | $324.9
|Average Commercial Paper Outstanding |  | $174.2                                        |  | $117.8
|Weighted Average Interest Rate       |  | 5.02%                                         |  | 3.26% 

We have entered into a bank back‐up credit agreement to maintain short‐term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65%.

---

Our bank back‐up credit agreement contains customary covenants, including certain limitations on our ability to sell assets.  The credit agreement also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control.

At December 31, 2006, we were in compliance with all covenants.





I ‐‐ ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our AROs during 2006.



|                             | Balance atDecember 31, 2005 |  | Liabilities
Incurred |  | Liabilities
Settled |  | Accretion |  | Balance at
December 31, 2006
|---------------------------- | --------------------------- |  | -------------------- |  | ------------------- |  | --------- |  | ----------------------------
|                             |                             |  |                      |  |                     |  |           |  |                             
|                             | (Millions of Dollars)      
|                             |                             |  |                      |  |                     |  |           |  |                             
|Asset Retirement Obligations | $354.9                      |  | $  ‐                 |  | ($2.1)              |  | $18.3     |  | $371.1                      



SFAS 143 primarily applies to the future decommissioning costs for Point Beach.  Prior to January 2003, we recorded a long‐term liability for accrued nuclear decommissioning costs.  See Note F for further information about the nuclear decommissioning of Point Beach, including our investments in nuclear decommissioning trusts that are restricted to nuclear decommissioning.

In March 2005, the FASB issued FIN 47.  FIN 47 defines a conditional ARO as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.  We adopted FIN 47 effective December 31, 2005.  At adoption, we recorded additional AROs related to asbestos removal costs.

The adoption of FIN 47 had no impact on our net income in 2006 or 2005.  As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs under FIN 47.  This treatment is consistent with the adoption of SFAS 143 for our regulated operations.





J ‐‐ DERIVATIVE INSTRUMENTS

We follow SFAS 133 as amended by SFAS 149, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.  For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities.  As of December 31, 2006, we recognized $18.5 million in regulatory assets related to derivatives in comparison to $2.2 million at December 31, 2005.

We had a limited number of financial contracts that are defined as derivatives under SFAS 133 and qualify for cash flow hedge accounting.  These contracts were utilized to manage the cost of gas for utility operations.  Changes in the fair market values of these instruments were recorded in Accumulated Other Comprehensive Income.  At the date the underlying transaction occurs, the amounts in Accumulated Other Comprehensive Income were reported in earnings.

For the year ended December 31, 2005 the amount of hedge ineffectiveness was immaterial.  We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness.

---

K ‐‐ FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount and estimated fair value of certain of our recorded financial instruments at December 31 are as follows:



|                                        |  | 2006                  |  | 2005      
|--------------------------------------- |  | --------------------- |  | ----------
|                                        |  |                       |  |           
|Financial Instruments                   |  | Carrying
Amount       |  | Fair
Value
|                                        |  |                       |  |           
|                                        |  | (Millions of Dollars)
|                                        |  |                       |  |           
|Nuclear decommissioning assets          |  | $881.6                |  | $881.6    
|Preferred stock, no redemption required |  | $30.4                 |  | $22.6     
|Long‐term debt including                |  |                       |  |           
|current portion                         |  | $1,601.6              |  | $1,588.9  



The carrying value of cash and cash equivalents, net accounts receivable, accounts payable and short‐term borrowings approximates fair value due to the short‐term nature of these instruments.  The nuclear decommissioning assets are carried at fair value as reported by the trustee (see Note F).  The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues.  The fair value of our long‐term debt, including the current portion of long‐term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.  The fair values of derivative financial instruments and associated margin accounts are equal to their carrying values as of December 31, 2006.





L ‐‐ BENEFITS

Pensions and Other Post‐retirement Benefits:   We participate in Wisconsin Energy's noncontributory defined benefit pension plans that cover substantially all of our employees.  The plans provide defined benefits based upon years of service and final average salary.  In October 2006, Wisconsin Energy announced that it was making a change to pension benefits for new management employees hired subsequent to October 2006 and for those represented employees whose unions have adopted this plan.  The retirement benefit for new employees is an enhanced 401(k) plan.  Existing employee's pension benefits are unchanged.  Our 2007 combined pension and savings plan costs are not expected to be materially affected as a result of this change to the plan.

We also participate in Wisconsin Energy's OPEB plans that cover substantially all of our employees.  The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory.  The accounting for the health care plans anticipates future cost‐sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels.  The post‐retirement health care plans include a limit on our share of costs for recent and future retirees.  Wisconsin Energy uses a year end measurement date for all of the pension and OPEB plans.

The assets, obligations and the components of our pension costs are allocated by Wisconsin Energy's actuary to each of the participating companies as if each participating company had its own plan.  The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy's pension plan.

In September 2006, the FASB issued SFAS 158, which requires employers to recognize all obligations related to their pension and OPEB plans and to quantify the funded status of the pension and OPEB plans as an asset or liability on their statement of financial position.  In addition, SFAS 158 requires employers to measure the funded status of their plans as of the date of their year‐end statement of financial position.

---

Wisconsin Energy adopted SFAS 158 prospectively on December 31, 2006.  Wisconsin Energy has historically and will continue to use a year end measurement date for all of the benefit plans.  Prior to the issuance of SFAS 158, we recorded a minimum pension liability to reflect the funded status of the pension plan.  Due to the regulatory nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

The following table shows the incremental effect of applying SFAS 158 on individual line items in our year‐end statement of financial position and compares prior year‐end balances:



|                                 | December 31, 2006     |         |             |  |                      
|-------------------------------- | --------------------- | ------- | ----------- |  | ---------------------
|                                 |                       |         |             |  |                      
|                                 | Before
SFAS 158       | Impact  | As Reported |  |                      
|                                 |                       |         |             |  |                      
|                                 | (Millions of Dollars) |         |             |  | (Millions of Dollars)
|                                 |                       |         |             |  |                      
|Regulatory Asset ‐ Pension       | $166.0                | $  70.3 | $236.3      |  |                      
|Regulatory Asset ‐ OPEB          | $    ‐                | $  29.2 | $  29.2     |  |                      
|Other Deferred Charges ‐ Pension | $  29.2               | ($29.2) | $    ‐      |  |                      
|Other Deferred Charges ‐ OPEB    | $    ‐                | $    ‐  | $    ‐      |  |                      
|                                 |                       |         |             |  |                      
|Pension Liability                | $264.1                | $  30.5 | $294.6      |  |                      
|OPEB Liability                   | $112.5                | $  29.2 | $141.7      |  |                      
|Other Comprehensive Income       | ($10.6)               | $  10.6 | $    ‐      |  |                      



The following table presents additional details about the pension and OPEB plans.



|                                  |  | Pension               |  | OPEB    
|--------------------------------- |  | --------------------- |  | --------
|                                  |  |                       |  |         
|Status of Benefit Plans           |  | 2006                  |  | 2005    
|                                  |  |                       |  |         
|                                  |  | (Millions of Dollars)
|Change in Benefit Obligation      |  |                       |  |         
|Benefit Obligation at January 1   |  | $1,109.1              |  | $1,019.5
|Service cost                      |  | 30.6                  |  | 30.0    
|Interest cost                     |  | 59.6                  |  | 59.4    
|Plan amendments                   |  | 3.0                   |  | 2.8     
|Actuarial loss (gain)             |  | (40.8)                |  | 77.3    
|Benefits paid                     |  | (89.7)                |  | (79.9)  
|Federal Subsidy on benefits paid  |  | N/A                   |  | N/A     
|                                  |  |                       |  |         
|Benefit Obligation at December 31 |  | $1,071.8              |  | $1,109.1
|                                  |  |                       |  |         
|                                  |  |                       |  |         
|Change in Plan Assets             |  |                       |  |         
|Fair Value at January 1           |  | $719.6                |  | $748.0  
|Actual earnings on plan assets    |  | 89.1                  |  | 48.6    
|Employer contributions            |  | 58.2                  |  | 2.9     
|Benefits paid                     |  | (89.7)                |  | (79.9)  
|                                  |  |                       |  |         
|Fair Value at December 31         |  | $777.2                |  | $719.6  
|                                  |  |                       |  |         
|                                  |  |                       |  |         
|Funded Status of Plans            |  |                       |  |         
|Funded status at December 31      |  | ($294.6)              |  | ($389.5)
|Unrecognized(1)                   |  |                       |  |         
|Net actuarial loss                |  | N/A                   |  | 297.5   
|Prior service cost                |  | N/A                   |  | 31.4    
|Net transition (asset) obligation |  | N/A                   |  | ‐       
|                                  |  |                       |  |         
|Accrued Benefit Cost              |  | ($294.6)              |  | ($60.6) 
|                                  |  |                       |  |         
|                                  |  |                       |  |         
|                                  |  |                       |  |         



|(1) | After adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer needed.
|--- | ------------------------------------------------------------------------------------------------------------------------

---



The accumulated benefit obligation for all the defined benefit plans was $1,041.5 million and $1,067.2 million at December 31, 2006 and 2005, respectively.

Information for the pension plan, which has an accumulated benefit obligation in excess of the fair value of its assets, is as follows:



|                               | 2006                  |  | 2005    
|------------------------------ | --------------------- |  | --------
|                               |                       |  |         
|                               | (Millions of Dollars)
|                               |                       |  |         
|Projected benefit obligation   | $1,071.8              |  | $1,109.1
|Accumulated benefit obligation | $1,041.5              |  | $1,067.2
|Fair value of plan assets      | $777.2                |  | $719.6  



The components of net periodic pension and OPEB costs are:



|                                               |  | Pension               |  | OPEB      
|---------------------------------------------- |  | --------------------- |  | ----------
|                                               |  |                       |  |           
|Benefit Plan Cost Components                   |  | 2006                  |  | 2005      
|                                               |  |                       |  |           
|                                               |  | (Millions of Dollars)
|Net Periodic Benefit Cost                      |  |                       |  |           
|Service cost                                   |  | $30.6                 |  | $30.0     
|Interest cost                                  |  | 59.6                  |  | 59.4      
|Expected return on plan assets                 |  | (59.8)                |  | (64.4)    
|Amortization of:                               |  |                       |  |           
|Transition (asset) obligation                  |  | ‐                     |  | (0.1)     
|Prior service cost                             |  | 5.4                   |  | 5.2       
|Actuarial loss                                 |  | 20.2                  |  | 17.9      
|                                               |  |                       |  |           
|Net Periodic Benefit Cost                      |  | $56.0                 |  | $48.0     
|                                               |  |                       |  |           
|                                               |  |                       |  |           
|                                               |  |                       |  |           
|                                               |  |                       |  |           
|Weighted‐Average assumptions used to           |  |                       |  |           
|determine benefit obligations at Dec 31        |  |                       |  |           
|                                               |  |                       |  |           
|Discount rate                                  |  | 5.75%                 |  | 5.50%     
|Rate of compensation increase                  |  | 4.5 to 5.0            |  | 4.5 to 5.0
|                                               |  |                       |  |           
|Weighted‐Average assumptions used to           |  |                       |  |           
|determine net cost for year ended Dec 31       |  |                       |  |           
|                                               |  |                       |  |           
|Discount rate                                  |  | 5.50%                 |  | 5.75%     
|Expected return on plan assets                 |  | 8.5                   |  | 9.0       
|Rate of compensation increase                  |  | 4.5 to 5.0            |  | 4.5 to 5.0
|                                               |  |                       |  |           
|Assumed health care cost trend rates at Dec 31 |  |                       |  |           
|                                               |  |                       |  |           
|Health care cost trend rate assumed for        |  |                       |  |           
|next year (Pre 65 / Post 65)                   |  |                       |  |           
|Rate that the cost trend rate gradually        |  |                       |  |           
|adjusts to                                     |  |                       |  |           
|Year that the rate reaches the rate it is      |  |                       |  |           
|assumed to remain at                           |  |                       |  |           
|                                               |  |                       |  |           

The expected long‐term rate of return on plan assets was 8.5% in 2006 and 9% in 2005 and 2004.  This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long‐term market returns for each of the asset categories utilized in the pension fund.

---

Other Post‐retirement Benefits Plans:   We use various Employees' Benefit Trusts to fund a major portion of OPEB.  The majority of the trusts' assets are mutual funds or commingled indexed funds.

A one‐percentage‐point change in assumed health care cost trend rates would have the following effects:



|                                              | 1% Increase           |  | 1% Decrease
|--------------------------------------------- | --------------------- |  | -----------
|                                              |                       |  |            
|                                              | (Millions of Dollars)
|Effect on                                     |                       |  |            
|Post‐retirement benefit obligation            | $25.2                 |  | ($21.1)    
|Total of service and interest cost components | $3.7                  |  | ($3.0)     



In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) was signed into law.  The Act introduced a prescription drug benefit program under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans.  In 2004, the FASB issued FSP SFAS 106‐2.

In 2004, in accordance with FSP SFAS 106‐2, we chose to recognize the effects of the Act retroactively effective January 1, 2004.  Calculated actuarially, the Act resulted in a reduction of $20.6 million in our benefit obligation.  In addition, we recorded a reduction to SFAS 106 expense of $4.2 million in 2004.  In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare.  It was determined that our employer sponsored plans met these regulations and that the previously determined actuarial measurements do not need to be revised.

In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post‐retirement medical and drug plans.  The Medicare Advantage program is part of the Act, and offers post‐65 medical and drug benefits through private insurance carriers.  The Medicare Advantage program is expected to reduce the cost of post‐65 medical and drug costs for our retirees and the Company.  Due to this change, we remeasured the fair value of our OPEB plans in the fourth quarter of 2005 in accordance with SFAS 106.  In 2005, the impact of this remeasurement and the FSP SFAS 106‐2 benefit was approximately a $4.1 million reduction to SFAS 106 expense.

Plan Assets:   In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees.  The pension plans asset allocation at December 31, 2006 and 2005, and the target allocation for 2007, by asset category, are as follows:



|                  |      | Target
Allocation |  | Actual Allocation
|----------------- | ---- | ----------------- |  | -----------------
|                  |      |                  
|Asset Category    | 2007 | 2006              |  | 2005             
|                  |      |                   |  |                  
|                  |      |                   |  |                  
|Equity Securities |      | 65%               |  | 61%              
|Debt Securities   |      | 35%               |  | 39%              
|                  |      |                   |  |                  
|Total             |      | 100%              |  | 100%             
|                  |      |                   |  |                  
|                  |      |                   |  |                  
|                  |      |                   |  |                  

---

Our OPEB plans asset allocation at December 31, 2006 and 2005, and our target allocation for 2007, by asset category, are as follows:



|                  |      | Target
Allocation |  | Actual Allocation
|----------------- | ---- | ----------------- |  | -----------------
|                  |      |                  
|Asset Category    | 2007 | 2006              |  | 2005             
|                  |      |                   |  |                  
|                  |      |                   |  |                  
|Equity Securities |      | 54%               |  | 32%              
|Debt Securities   |      | 46%               |  | 68%              
|Other             |      | ‐ %               |  | ‐ %              
|                  |      |                   |  |                  
|Total             |      | 100%              |  | 100%             
|                  |      |                   |  |                  
|                  |      |                   |  |                  
|                  |      |                   |  |                  

Wisconsin Energy's common stock is not included in equity securities.  Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund or index fund.

The target asset allocations were established by an Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans.  The asset allocations are monitored by the Investment Trust Policy Committee.



Cashflows:



|Employer Contributions |  | Pension               |  | OPEB 
|---------------------- |  | --------------------- |  | -----
|                       |  |                       |  |      
|                       |  | (Millions of Dollars)
|                       |  |                       |  |      
|2004                   |  | $72.4                 |  | $15.7
|2005                   |  | $2.9                  |  | $9.1 
|2006                   |  | $58.2                 |  | $12.5

Based on our PSCW approved funding policy and current IRS funding requirements, we expect to contribute $36.5 million to fund pension benefits and $11.2 million to fund OPEB plans in 2007.  Of the $36.5 million expected to be contributed to fund pension benefits in 2007, we estimate $32.4 million will be for our qualified pension plans.  We contributed $54.0 million to our qualified pension plans during 2006.  We did not make a contribution to our qualified pension plan during 2005.

The entire contribution to the OPEB plans during 2006 was discretionary as the plans are not subject to any minimum regulatory funding requirements.

The following table identifies our expected benefit payments over the next 10 years:



|Year      |  | Pension               |  | Gross OPEB |  | Expected
Medicare
Part D
Subsidy
|--------- |  | --------------------- |  | ---------- |  | --------------------------------
|          |  |                       |  |            |  |                                 
|          |  | (Millions of Dollars)
|          |  |                       |  |            |  |                                 
|2007      |  | $72.0                 |  | $13.8      |  | ($1.0)                          
|2008      |  | $77.7                 |  | $14.2      |  | ($0.8)                          
|2009      |  | $80.4                 |  | $13.0      |  | ‐                               
|2010      |  | $81.2                 |  | $14.3      |  | ‐                               
|2011      |  | $92.3                 |  | $15.6      |  | ‐                               
|2012‐2016 |  | $453.9                |  | $96.8      |  | ‐                               

---



Savings Plans:   We sponsor savings plans which allow employees to contribute a portion of their pre‐tax and or after‐tax income in accordance with plan‐specified guidelines.  Under these plans, we expensed matching contributions of $9.3 million, $9.5 million and $9.1 million during 2006, 2005 and 2004, respectively.

Severance Plans:   In 2004, we incurred $22.3 million ($13.4 million after‐tax) of severance costs.  The majority of the severance costs related to an enhanced severance package offered to selected management employees of Wisconsin Energy and its subsidiaries who voluntarily resigned in the fourth quarter of 2004.  The program was enacted to help reduce the upward pressure on operating expenses.

Approximately 150 employees received severance benefits during 2004.  At December 31, 2004, we accrued $6.6 million for severance benefits. As of December 31, 2006, all of the severance related benefits were paid.





M ‐‐ GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties.  As of December 31, 2006, we had the following guarantees:



|           |  | Maximum
Potential
Future
Payments |  | Outstanding at
Dec 31, 2006 |  | Liability 
Recorded at
Dec 31, 2006
|---------- |  | --------------------------------- |  | --------------------------- |  | -----------------------------------
|           |  |                                   |  |                             |  |                                    
|           |  | (Millions of Dollars)            
|           |  |                                   |  |                             |  |                                    
|Guarantees |  | $235.2                            |  | $0.1                        |  | $ ‐                                

We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program (See Note F).

Postemployment benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs.  The estimated liability, excluding severance benefits, for such benefits was $9.0 million as of December 31, 2006.





N ‐‐ COMMON EQUITY

Share‐Based Compensation Plans:   Employees of Wisconsin Electric participate in a plan approved by Wisconsin Energy stockholders that provides a long‐term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries.  The plan provides for the granting of Wisconsin Energy stock options, stock appreciation rights, restricted stock awards and performance shares.  Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof.

---

The following is a summary of Wisconsin Energy stock options held by our employees and issued through December 31, 2006:



|                           |  | 2006               |  | 2005                                |  | 2004              
|-------------------------- |  | ------------------ |  | ----------------------------------- |  | ------------------
|                           |  |                    |  |                                     |  |                   
|Stock Options              |  | Number
of
 Options |  | Weighted‐
Average
Exercise
   Price |  | Number
of
 Options
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   
|Outstanding at January 1   |  | 5,985,653          |  | $28.99                              |  | 5,656,042         
|Granted                    |  | 1,169,907          |  | $39.51                              |  | 1,136,150         
|Exercised                  |  | (856,942)          |  | $25.03                              |  | (801,026)         
|Forfeited                  |  | (26,931)           |  | $36.79                              |  | (5,513)           
|                           |  |                    |  |                                     |  |                   
|Outstanding at December 31 |  | 6,271,687          |  | $31.46                              |  | 5,985,653         
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   
|Exercisable at December 31 |  | 3,996,938          |  | $28.38                              |  | 4,834,833         
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   
|                           |  |                    |  |                                     |  |                   



The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding at December 31, 2006:



|                                     |  | Options Outstanding |  | Options Exercisable
|------------------------------------ |  | ------------------- |  | -------------------
|                                     |  |                     |  |                    
|                                     |  |                     |  | Weighted Average   
|                                     |  |                     |  |                    
|Range of Exercise Prices             |  | Number              |  | Exercise
   Price  
|                                     |  |                     |  |                    
|$11.58  to  $23.05                   |  | 860,770             |  | $21.54             
|$25.31  to  $31.07                   |  | 1,561,819           |  | $27.02             
|$33.44  to  $42.56                   |  | 3,849,098           |  | $35.48             
|                                     |  |                     |  |                    
|                                     |  | 6,271,687           |  | $31.46             
|                                     |  |                     |  |                    
|                                     |  |                     |  |                    
|                                     |  |                     |  |                    
|                                     |  |                     |  |                    
|Aggregate Intrinsic Value (Millions) |  | Options Outstanding |  | Options Exercisable
|                                     |  |                     |  |                    
|December 31, 2006                    |  | $100.3              |  | $76.3              

In January 2007, the Compensation Committee awarded 1,247,760 non‐qualified Wisconsin Energy stock options at the average market price of $47.76 to our officers and key employees under its normal schedule of awarding long‐term incentive compensation.

We utilize the straight‐line attribution method for recognizing stock‐based compensation expense under SFAS 123R.  We recorded compensation expense, net of tax, for stock option awards made to our officers and other key employees of $4.1 million for the twelve months ended December 31, 2006.

The aggregate intrinsic value of stock options exercised during the twelve months ended December 31, 2006 was approximately $16.0 million.  Tax benefits associated with our stock option awards for the twelve months ended December 31, 2006 were $6.4 million.

The exercise price of a Wisconsin Energy stock option under the plan is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control.  In December 2004, the Compensation Committee approved the acceleration of vesting of all unvested options awarded to our officers and other key employees in 2002, 2003 and 2004.  In addition, the Compensation Committee determined that future option grants would be non‐qualified stock options and they would vest on a cliff‐basis after a three year period.  The stock options that were granted prior to 2005 generally vest on a straight line basis over a four year period.  Generally, options expire no later than ten years

---

On December 31, 2005, the value of our non‐vested Wisconsin Energy stock options outstanding was $9.6 million, or $8.32 per share on a weighted average grant date fair value basis.  On December 31, 2006, the value of our Wisconsin Energy non‐vested stock options outstanding was $18.0 million or $7.93 per share on a weighted average grant date fair value basis.  During the year, 19,047 stock options vested and 26,931 stock options were forfeited on a weighted average grant date fair value of $7.71 and $7.94, respectively.

As of December 31, 2006, total compensation costs related to non‐vested stock options not yet recognized was approximately $8.0 million, which is expected to be recognized over the next 19 months on a weighted‐average basis.

The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain of our key employees and directors.  The following restricted stock activity related to our employees occurred during 2006, 2005 and 2004:



|                           |  | 2006              |  | 2005                              |  | 2004             
|-------------------------- |  | ----------------- |  | --------------------------------- |  | -----------------
|                           |  |                   |  |                                   |  |                  
|Restricted Shares          |  | Number
of
 Shares |  | Weighted‐
Average
Market
   Price |  | Number
of
 Shares
|                           |  |                   |  |                                   |  |                  
|                           |  |                   |  |                                   |  |                  
|Outstanding at January 1   |  | 150,772           |  |                                   |  | 180,614          
|Granted                    |  | 2,500             |  | $40.35                            |  | ‐                
|Released / Forfeited       |  | (21,327)          |  | $26.91                            |  | (29,842)         
|                           |  |                   |  |                                   |  |                  
|Outstanding at December 31 |  | 131,945           |  |                                   |  | 150,772          
|                           |  |                   |  |                                   |  |                  
|                           |  |                   |  |                                   |  |                  
|                           |  |                   |  |                                   |  |                  

Recipients of the Wisconsin Energy restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service.  Forfeiture provisions on the restricted stock generally expire 10 years after award grant subject to an accelerated expiration schedule for some of the shares based on the achievement of certain financial performance goals.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards.  We also adjust expense for acceleration of vesting due to achievement of performance goals.  We recorded compensation expense, net of tax, for restricted stock awards made to our employees and directors of $0.2 million for the twelve months ended December 31, 2006.  Tax benefits realized for our restricted stock awards were $0.3 million for the twelve months ended December 31, 2006.  As of December 31, 2006, total compensation cost related to non‐vested restricted stock awards not yet recognized was approximately $1.6 million, which is expected to be recognized over the next 62 months on a weighted‐average basis.



In January 2004, the Compensation Committee granted 139,793 Wisconsin Energy performance shares to our officers and other key employees.  In January 2007, 2006 and 2005, the Compensation Committee granted 124,160, 134,818 and 90,739 Wisconsin Energy performance units to our officers and other key employees under the Wisconsin Energy Performance Unit Plan.  Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three year period.  Under the terms of the award, participants may earn between 0% and 175% of the base performance award.  We are accruing compensation costs over the three year period based on an estimate of the final expected value of the award.  In July 2006, the Compensation Committee amended the terms of the performance shares to allow the recipients of 2004 grants to receive cash or common stock upon settlement.  The 2005, 2006 and 2007 grants will be settled in cash.  We recorded compensation expense, net of tax, for performance awards made to our employees of $3.6 million for the twelve months ended December 31, 2006.  We have not realized any tax benefits associated with our performance awards during the twelve months ended December 31, 2006.  As of December 31, 2006, total compensation cost related to non‐vested performance awards not yet recognized was approximately $5.5 million, which is expected to be recognized over the next 21 months on a weighted‐average

---

Equity Contribution:   Our capitalization reflects the impact of an equity contribution from Wisconsin Energy.  An equity contribution of $100.0 million was made during the second quarter of 2006.

Restrictions:   Our January 2006 rate order from the PSCW requires us to maintain a capital structure (i.e., the percentage by which each of common stock, preferred stock and debt constitute the total capital invested in the utility), which has a common equity ratio range of between 48.5% and 53.5% (including certain off‐balance sheet obligations and capitalized leases, but excluding the PWGS 1 capitalized lease).  As of December 31, 2006, our restricted net assets were approximately $2.2 billion.  Previously in a June 2004 decision, the PSCW determined that we must obtain specific approval to pay dividends that exceed normal levels as long as any tax issue or appeals related to the sale of Wisconsin Energy's manufacturing business and/or the conversion of Wisconsin Gas to a limited liability company remain outstanding.  The PSCW may modify such provisions by a future order.

We may not pay common dividends to Wisconsin Energy under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid.  In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined, is less than 25% and 20%, respectively.

See Note H for discussion of certain financial covenants related to our bank back‐up credit agreements.

We do not believe that these restrictions will materially affect our operations or limit any normal dividend payments in the foreseeable future.





O ‐‐ SEGMENT REPORTING

We are a wholly‐owned subsidiary of Wisconsin Energy and have organized our operating segments according to how we are currently regulated.  Our reportable operating segments include electric, natural gas and steam utility segments.  The accounting policies of the reportable operating segments are the same as those described in Note A.

Our electric utility engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan.  Our natural gas utility is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer‐owned natural gas in three service areas in southeastern, east central and northern Wisconsin.  Our steam utility produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.

---

Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2006, 2005 and 2004, is shown in the following table.





|                              |  | Reporting Operating Segments |  |        |  |       
|----------------------------- |  | ---------------------------- |  | ------ |  | ------
|                              |  |                              |  |        |  |       
|Year Ended                    |  | Electric                     |  | Gas    |  | Steam 
|                              |  |                              |  |        |  |       
|                              |  | (Millions of Dollars)       
|December 31, 2006             |  |                              |  |        |  |       
|                              |  |                              |  |        |  |       
|Operating Revenues (b)        |  | $2,499.5                     |  | $590.0 |  | $27.2 
|Depreciation, Decommissioning |  |                              |  |        |  |       
|and Amortization              |  | $234.8                       |  | $32.4  |  | $3.7  
|Operating Income (c)          |  | $407.2                       |  | $47.7  |  | $1.0  
|Equity in Earnings            |  |                              |  |        |  |       
|of Transmission Affiliate     |  | $33.9                        |  | $   ‐  |  | $   ‐ 
|Capital Expenditures          |  | $362.4                       |  | $33.6  |  | $2.6  
|Total Assets (d)              |  | $7,416.6                     |  | $666.2 |  | $59.2 
|                              |  |                              |  |        |  |       
|December 31, 2005             |  |                              |  |        |  |       
|                              |  |                              |  |        |  |       
|Operating Revenues (b)        |  | $2,320.9                     |  | $593.6 |  | $23.5 
|Depreciation, Decommissioning |  |                              |  |        |  |       
|and Amortization              |  | $242.7                       |  | $35.8  |  | $3.3  
|Operating Income (Loss) (c)   |  | $437.5                       |  | $41.5  |  | ($1.7)
|Equity in Earnings            |  |                              |  |        |  |       
|of Transmission Affiliate     |  | $30.4                        |  | $   ‐  |  | $   ‐ 
|Capital Expenditures          |  | $374.2                       |  | $28.4  |  | $4.6  
|Total Assets (d)              |  | $7,020.2                     |  | $709.0 |  | $58.9 
|                              |  |                              |  |        |  |       
|December 31, 2004             |  |                              |  |        |  |       
|                              |  |                              |  |        |  |       
|Operating Revenues (b)        |  | $2,070.8                     |  | $523.8 |  | $22.0 
|Depreciation, Decommissioning |  |                              |  |        |  |       
|and Amortization              |  | $234.9                       |  | $36.1  |  | $3.1  
|Operating Income (Loss) (c)   |  | $427.2                       |  | $33.1  |  | ($1.1)
|Equity in Earnings            |  |                              |  |        |  |       
|of Transmission Affiliate     |  | $26.4                        |  | $   ‐  |  | $   ‐ 
|Capital Expenditures          |  | $313.7                       |  | $33.2  |  | $6.7  
|Total Assets (d)              |  | $6,153.0                     |  | $667.1 |  | $54.0 
|                              |  |                              |  |        |  |       



|(a) | Other includes primarily non‐utility property and investments, materials and supplies, deferred charges and other corporate items.                                                        
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                           
|(b) | We account for intersegment revenues at a tariff rate established by the PSCW.  Intersegment revenues are not material.                                                                   
|    |                                                                                                                                                                                           
|(c) | We evaluate operating income to manage our utility business.  Equity in Earnings of TransmissionAffiliate, Interest Expense and Income Taxes are not included in segment operating income.
|    |                                                                                                                                                                                           
|(d) | Common utility plant is allocated to electric, gas and steam utility operations to determine segment assets (see Note A).                                                                 

---

P ‐‐ RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW.  In addition, we make lease payments to We Power for PWGS 1 and the other generating facilities being constructed under Wisconsin Energy'sPTF strategy, and we sell electric energy to an affiliated utility, Edison Sault.  We also receive and/or provide certain services to other associated companies in which we have, or Wisconsin Energy has, an equity investment.

ATC:   As of December 31, 2006, we have a 25.8% interest in ATC.  We pay ATC for transmission and other related services it provides.  In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC.  Under Wisconsin Energy's PTF plan, we are required to pay the cost of needed transmission infrastructure upgrades.  ATC will reimburse us for these costs when the units are placed into service.  At December 31, 2006 and 2005, we had a receivable of $27.2 million and $19.4 million, respectively, for these items.

NMC:   At December 31, 2006, NMC, which operates Point Beach, was owned by Wisconsin Energy's affiliate, WEC Nuclear Corporation, and the affiliates of two other unaffiliated investor‐owned utilities in the region.  We pay NMC a plant operating charge.  In December 2006, we announced our intention to sell Point Beach to an affiliate of FPL.  If and when the sale is completed (or earlier if an interim operating agreement with FPL is activated by us), the operating licenses for Point Beach will transfer from NMC to the buyer and our relationship with NMC will be terminated.

Guardian:   In April 2006, Wisconsin Energy sold its one third ownership interest in Guardian.  As such, the tables below reflect activity through April 2006 with respect to Guardian.  Wisconsin Gas has committed to purchase 650,000 Dth per day of capacity under the terms of a 10 year transportation agreement expiring December 2022.  Under a PSCW‐approved agreement, we have purchased some of this capacity from Wisconsin Gas when they have excess, and we expect to continue to do so.

We provided and received services from the following associated companies during 2006, 2005 and 2004:



|Company                                        |  | 2006                  |  | 2005   |  | 2004  
|---------------------------------------------- |  | --------------------- |  | ------ |  | ------
|                                               |  |                       |  |        |  |       
|                                               |  | (Millions of Dollars)
|Wisconsin Electric Affiliate                   |  |                       |  |        |  |       
|                                               |  |                       |  |        |  |       
|Net Services Provided                          |  |                       |  |        |  |       
|‐We Power (excluding lease payments)           |  | $3.2                  |  | $3.8   |  | $3.3  
|‐Wisconsin Gas                                 |  | $44.4                 |  | $48.8  |  | $50.4 
|‐Edison Sault (including electric energy sold) |  | $22.6                 |  | $21.5  |  | $15.6 
|‐Minergy                                       |  | $3.6                  |  | $8.1   |  | $7.3  
|‐Other                                         |  | $1.5                  |  | $1.5   |  | $1.9  
|                                               |  |                       |  |        |  |       
|Net Services Received                          |  |                       |  |        |  |       
|‐We Power (lease payments)                     |  | $135.3                |  | $79.8  |  | $59.0 
|‐Wisconsin Energy                              |  | $9.1                  |  | $6.6   |  | $2.9  
|                                               |  |                       |  |        |  |       
|Equity Investee                                |  |                       |  |        |  |       
|Services Provided                              |  |                       |  |        |  |       
|‐ATC                                           |  | $15.8                 |  | $20.0  |  | $20.7 
|                                               |  |                       |  |        |  |       
|Services Received                              |  |                       |  |        |  |       
|‐ATC                                           |  | $145.7                |  | $126.8 |  | $112.5
|‐NMC                                           |  | $65.2                 |  | $61.2  |  | $58.1 
|‐Guardian                                      |  | $3.9                  |  | $12.0  |  | $11.4 

---

At December 31, 2006 and 2005, our consolidated balance sheets included receivable and payable balances with the following equity investee companies:



|Company             |  | 2006                  |  | 2005 
|------------------- |  | --------------------- |  | -----
|                    |  |                       |  |      
|                    |  | (Millions of Dollars)
|Equity Investee     |  |                       |  |      
|Accounts Receivable |  |                       |  |      
|‐ATC                |  | $1.2                  |  | $1.2 
|                    |  |                       |  |      
|Accounts Payable    |  |                       |  |      
|‐ATC                |  | $12.1                 |  | $10.3
|‐NMC                |  | $5.7                  |  | $2.5 
|‐Guardian           |  | $  ‐                  |  | $1.0 





Q ‐‐ COMMITMENTS AND CONTINGENCIES

Capital Expenditures:   We have made certain commitments in connection with 2007 capital expenditures.  During 2007, we estimate that total capital expenditures will be approximately $600 million, excluding the purchase of nuclear fuel.

Operating Leases:   We enter into long‐term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs.  These contracts expire at various times through 2013.  Certain of these contracts were deemed to qualify as operating leases.  In addition, we have various other operating leases, including leases for vehicles and coal cars.

Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:



|           | (Millions of Dollars)
|---------- | ---------------------
|           |                      
|           |                      
|2007       | $51.6                
|2008       | 35.7                 
|2009       | 22.5                 
|2010       | 20.5                 
|2011       | 20.7                 
|Thereafter | 32.9                 
|           |                      
|Total      | $183.9               
|           |                      
|           |                      
|           |                      



Environmental Matters:

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal‐ash disposal sites.  We perform ongoing assessments of our manufactured gas plant sites and related disposal sites, as well as coal ash disposal/landfill sites.  We are working with the WDNR in our investigation and remediation planning.  At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites:   We have identified several sites at which we or a predecessor company historically owned or operated a manufactured gas plant.  We have substantially completed planned remediation activities at some of those sites and certain other sites are subject to ongoing monitoring.  Remediation at additional sites is currently being performed, and other sites are being investigated or monitored.  We have also identified other sites that may have been impacted by historical manufactured gas plant activities.  Based upon ongoing analysis, we

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The PSCW has allowed Wisconsin utilities, including us, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years.  Accordingly, we have recorded a regulatory asset for remediation costs.

Ash Landfill Sites:   We aggressively seek environmentally acceptable, beneficial uses for our coal combustion by‐products.  However, these coal‐ash by‐products have been, and to a small degree, continue to be disposed in company‐owned, licensed landfills.  Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting.  Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions.  The costs of these efforts are recovered under our fuel clause and are expensed as incurred.  During 2006, 2005 and 2004, we incurred $0.5 million, $0.1 million and $1.8 million, respectively, in coal‐ash remediation expenses.  As of December 31, 2006 we have no reserves established related to ash landfill sites.

EPA ‐ Proposed Consent Decree:   In April 2003, we and the EPA announced that a consent decree had been reached that resolved all issues related to a request for information that had been issued by the EPA.  Under the consent decree, we agreed to significantly reduce our air emissions from our coal‐fired generating facilities.  The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment and retiring certain older units.  Through December 31, 2006, we have spent approximately $355.0 million associated with implementing the EPA agreement and the ultimate capital cost of implementing this agreement is estimated to be $1 billion through the year 2013.

The consent decree, amended to include the State of Michigan, has been filed with a federal court for approval.  Various intervenor groups have commented on the consent decree and we believe that the briefings and subsequent discovery is complete.  At this time, we are unable to predict the timing or the ultimate resolution of the federal court's consideration; however, we do not believe that the ultimate resolution of this matter will have a material impact on our financial position or results of operations.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary ("the Company") as of December 31, 2006 and 2005, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2006.  Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2).  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLPDeloitte & Touche LLP

Milwaukee, Wisconsin
February 22, 2007

---

|ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON 
ACCOUNTING AND FINANCIAL DISCLOSURE
|------- | -------------------------------------------------------------------------------------

None.





|ITEM 9A. | CONTROLS AND PROCEDURES
|-------- | -----------------------

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a‐15(e) and 15d‐15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report.  Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.



Changes in Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting during the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.





|ITEM 9B. | OTHER INFORMATION
|-------- | -----------------

Larry Salustro, Executive Vice President of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas, retired effective February 28, 2007.  In connection with Mr. Salustro's retirement and in consideration of his exemplary service to all three companies, on February 26, 2007, the Compensation Committee approved the acceleration of vesting of all unvested stock options awarded to Mr. Salustro, consisting of 324,000 options.





PART III

|ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
|-------- | ------------------------------------------------------------------------

The information under "Election of Directors", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance ‐‐ Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to the Corporate Governance Committee?", "Corporate Governance ‐‐ Frequently Asked Questions: Are the Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance ‐‐ Frequently Asked Questions: Are all the members of the audit committee financially literate and does the committee have an "audit committee financial expert?", "Corporate Governance ‐‐ Frequently Asked Questions: Does the Board have a nominating committee?" and "Committees of the Board of Directors ‐‐ Audit and Oversight" in our definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Stockholders to be held April 30, 2007 (the "2007 Annual Meeting Information Statement") is incorporated herein by reference.  Also see "Executive Officers of the Registrant" in Part I of this report.

Wisconsin Energy has adopted a written code of ethics, referred to as its Code of Business Conduct.  We are a wholly owned subsidiary of Wisconsin Energy, and as such, all of our directors, executive officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a

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|ITEM 11. | EXECUTIVE COMPENSATION
|-------- | ----------------------

The information under "COMPENSATION DISCUSSION AND ANALYSIS", "EXECUTIVE OFFICERS' COMPENSATION", "DIRECTOR COMPENSATION", "Committees of the Board of Directors ‐ Compensation", and "COMPENSATION COMMITTEE REPORT" in the 2007 Annual Meeting Information Statement is incorporated herein by reference.





|ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|-------- | ----------------------------------------------------------------------------------------------

All of our Common Stock (100% of such class) is owned by our parent company, Wisconsin Energy Corporation, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.  Our directors, director nominees and executive officers do not own any of our voting securities.  The information concerning their beneficial ownership in Wisconsin Energy common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 2007 Annual Meeting Information Statement is incorporated herein by reference.

We do not have any equity compensation plans under which our equity securities may be issued.  Our directors, officers and certain employees participate in the compensation plans of Wisconsin Energy Corporation.





|ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|-------- | -------------------------------------------------------------------------

The information under "Corporate Governance ‐ Frequently Asked Questions: Who are the independent directors?", "Corporate Governance ‐ Frequently Asked Questions: What are the Board's standards of independence" and "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS" in the 2007 Annual Meeting Information Statement is incorporated herein by reference.  A full description of the guidelines our Board uses to determine director independence is located in Appendix A of Wisconsin Energy's Corporate Governance Guidelines, which can be found on its website, www.wisconsinenergy.com.





|ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES
|-------- | --------------------------------------

The information regarding the fees paid to, and services performed by, our independent auditors and the pre‐approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2007 Annual Meeting Information Statement is incorporated herein by reference.

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PART IV

|ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|-------- | ------------------------------------------
|         |                                           

|(a) 1. | FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT
|------ | --------------------------------------------------------------------------------------------------------------------

Consolidated Income Statements for the three years ended December 31, 2006.

Consolidated Balance Sheets at December 31, 2006 and 2005.

Consolidated Statements of Cash Flows for the three years ended December 31, 2006.

Consolidated Statements of Capitalization at December 31, 2006 and 2005

Consolidated Statements of Common Equity for the three years ended December 31, 2006.

Notes to Consolidated Financial Statements.

Report of Independent Registered Public Accounting Firm.





|2. | FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
|-- | ----------------------------------------------------------------

Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2006.

Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.





|3. | EXHIBITS AND EXHIBIT INDEX
|-- | --------------------------

See the Exhibit Index included as the last part of this report, which is incorporated herein by reference.  Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.

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SCHEDULE II ‐ VALUATION AND QUALIFYING ACCOUNTS



|Allowance for Doubtful Accounts |  | Balance at
Beginning of
the Period |  | Expense |  | Deferral |  | Net
Write‐offs |  | Balance at
End of the
Period
|------------------------------- |  | ---------------------------------- |  | ------- |  | -------- |  | -------------- |  | ----------------------------
|                                |  |                                    |  |         |  |          |  |                |  |                             
|                                |  | (Millions of Dollars)             
|                                |  |                                    |  |         |  |          |  |                |  |                             
|December 31, 2006               |  | $20.2                              |  | $15.9   |  | $6.0     |  | ($21.9)        |  | $20.2                       
|December 31, 2005               |  | $20.2                              |  | $14.4   |  | $9.7     |  | ($24.1)        |  | $20.2                       
|December 31, 2004               |  | $26.6                              |  | $8.9    |  | $11.7    |  | ($27.0)        |  | $20.2                       

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SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

|                      | WISCONSIN ELECTRIC POWER COMPANY                
|--------------------- | ------------------------------------------------
|                      |                                                 
|By                    | /s/GALE E. KLAPPA                               
|Date:   March 2, 2007 | Gale E. Klappa, Chairman of the Board, President
|                      | and Chief Executive Officer                     



Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



|/s/GALE E. KLAPPA                                                                                                        |  | March 2, 2007
|------------------------------------------------------------------------------------------------------------------------ |  | -------------
|Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director ‐‐ Principal Executive Officer |  |              
|                                                                                                                         |  |              
|/s/ALLEN L. LEVERETT                                                                                                     |  | March 2, 2007
|Allen L. Leverett, Executive Vice President and Chief
Financial Officer ‐‐ Principal Financial Officer                   |  |              
|                                                                                                                         |  |              
|/s/STEPHEN P. DICKSON                                                                                                    |  | March 2, 2007
|Stephen P. Dickson, Vice President and 
Controller ‐‐ Principal Accounting Officer                                       |  |              
|                                                                                                                         |  |              
|/s/JOHN F. AHEARNE                                                                                                       |  | March 2, 2007
|John F. Ahearne, Director                                                                                                |  |              
|                                                                                                                         |  |              
|/s/JOHN F. BERGSTROM                                                                                                     |  | March 2, 2007
|John F. Bergstrom, Director                                                                                              |  |              
|                                                                                                                         |  |              
|/s/BARBARA L. BOWLES                                                                                                     |  | March 2, 2007
|Barbara L. Bowles, Director                                                                                              |  |              
|                                                                                                                         |  |              
|/s/PATRICIA W. CHADWICK                                                                                                  |  | March 2, 2007
|Patricia W. Chadwick, Director                                                                                           |  |              
|                                                                                                                         |  |              
|/s/ROBERT A. CORNOG                                                                                                      |  | March 2, 2007
|Robert A. Cornog, Director                                                                                               |  |              
|                                                                                                                         |  |              
|/s/CURT S. CULVER                                                                                                        |  | March 2, 2007
|Curt S. Culver, Director                                                                                                 |  |              
|                                                                                                                         |  |              
|/s/THOMAS J. FISCHER                                                                                                     |  | March 2, 2007
|Thomas J. Fischer, Director                                                                                              |  |              
|                                                                                                                         |  |              
|/s/ULICE PAYNE, JR.                                                                                                      |  | March 2, 2007
|Ulice Payne, Jr., Director                                                                                               |  |              
|                                                                                                                         |  |              
|/s/FREDERICK P. STRATTON, JR.                                                                                            |  | March 2, 2007
|Frederick P. Stratton, Jr., Director                                                                                     |  |              

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WISCONSIN ELECTRIC POWER COMPANY
(Commission File No. 001‐01245)



EXHIBIT INDEX
to
Annual Report on Form 10‐K
For the year ended December 31, 2006





The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company.  (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b‐32.)

|Number |  | Exhibit                                                                    
|------ |  | ---------------------------------------------------------------------------
|       |  |                                                                            
|       |  |                                                                            
|2      |  | Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
|       |  |                                                                            
|       |  | 2.1*                                                                       
|       |  |                                                                            
|3      |  | Articles of Incorporation and By‐laws                                      
|       |  |                                                                            
|       |  | 3.1*                                                                       
|       |  |                                                                            
|       |  | 3.2*                                                                       
|       |  |                                                                            
|4      |  | Instruments defining the rights of security holders, including indentures  
|       |  |                                                                            
|       |  | 4.1*                                                                       
|       |  |                                                                            
|       |  | Indenture and Securities Resolutions:                                      
|       |  |                                                                            
|       |  | 4.2*                                                                       
|       |  |                                                                            
|       |  | 4.3*                                                                       
|       |  |                                                                            
|       |  | 4.4*                                                                       
|       |  |                                                                            
|       |  | 4.5*                                                                       
|       |  |                                                                            

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|Number |  | Exhibit           
|------ |  | ------------------
|       |  |                   
|       |  | 4.6*              
|       |  |                   
|       |  | 4.7*              
|       |  |                   
|       |  | 4.8*              
|       |  |                   
|       |  | 4.9*              
|       |  |                   
|       |  |                   
|       |  |                   
|       |  |                   
|10     |  | Material Contracts
|       |  |                   
|       |  | 10.1*             
|       |  |                   
|       |  | 10.2*             
|       |  |                   
|       |  | 10.3*             
|       |  |                   
|       |  | 10.4*             
|       |  |                   
|       |  | 10.5*             
|       |  |                   

---

|Number |  | Exhibit
|------ |  | -------
|       |  |        
|       |  | 10.6*  
|       |  |        
|       |  | 10.7*  
|       |  |        
|       |  | 10.8*  
|       |  |        
|       |  | 10.9*  
|       |  |        
|       |  | 10.10* 
|       |  |        
|       |  | 10.11* 
|       |  |        
|       |  | 10.12* 
|       |  |        
|       |  | 10.13* 
|       |  |        
|       |  | 10.14* 
|       |  |        
|       |  | 10.15* 
|       |  |        
|       |  | 10.16* 
|       |  |        
|       |  | 10.17* 

---

|Number |  | Exhibit
|------ |  | -------
|       |  |        
|       |  | 10.18* 
|       |  |        
|       |  | 10.19* 
|       |  |        
|       |  | 10.20* 
|       |  |        
|       |  | 10.21* 
|       |  |        
|       |  | 10.22* 
|       |  |        
|       |  | 10.23* 
|       |  |        
|       |  | 10.24* 
|       |  |        
|       |  | 10.25* 
|       |  |        
|       |  | 10.26* 
|       |  |        
|       |  | 10.27* 
|       |  |        
|       |  | 10.28* 
|       |  |        
|       |  | 10.29* 
|       |  |        
|       |  | 10.30* 

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|Number |  | Exhibit                                                                                                                                                                                                                                                                     
|------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.31*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.32*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.33*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.34*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.35*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.36*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.37*                                                                                                                                                                                                                                                                      
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.38                                                                                                                                                                                                                                                                       
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.38(a)*                                                                                                                                                                                                                                                                   
|       |  |                                                                                                                                                                                                                                                                             
|       |  | 10.38(b)*                                                                                                                                                                                                                                                                   
|       |  |                                                                                                                                                                                                                                                                             
|       |  | Note:  Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10‐K.                                                                                              
|       |  |                                                                                                                                                                                                                                                                             
|       |  | *** Wisconsin Energy has requested confidential treatment of certain portions of these documents pursuant to an application for confidential treatment sent to the SEC.  Wisconsin Energy has omitted such portions from this filing and filed them separately with the SEC.
|       |  |                                                                                                                                                                                                                                                                             

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|Number |  | Exhibit                                  
|------ |  | -----------------------------------------
|       |  |                                          
|21     |  | Subsidiaries of the registrant           
|       |  |                                          
|       |  | 21.1                                     
|       |  |                                          
|       |  |                                          
|23     |  | Consents of experts and counsel          
|       |  |                                          
|       |  | 23.1                                     
|       |  |                                          
|       |  |                                          
|31     |  | Rule 13a‐14(a) / 15d‐14(a) Certifications
|       |  |                                          
|       |  | 31.1                                     
|       |  |                                          
|       |  | 31.2                                     
|       |  |                                          
|       |  |                                          
|32     |  | Section 1350 Certifications              
|       |  |                                          
|       |  | 32.1                                     
|       |  |                                          
|       |  | 32.2                                     
|       |  |                                          
|       |  |                                          

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