WISCONSIN ELECTRIC POWER CO - Annual Report: 2005 (Form 10-K)

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, 2005 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, 2006):

Portions of Wisconsin Electric Power Company's definitive information statement for its Annual Meeting of Stockholders, to be held on April 28, 2006, are incorporated by reference into Part III hereof.

Wisconsin Electric Power Company (Wisconsin Electric), a wholly-owned subsidiary of Wisconsin Energy Corporation (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 1,092,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 446,400 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 LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault Electric Company (Edison Sault), an electric utility which serves customers in the Upper Peninsula of Michigan; and W.E. Power, LLC (We Power), an unregulated company that was formed in 2001 to design, construct, own, finance and lease to us the new generating capacity included in Wisconsin Energy's Power the Future 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".

Power the Future Strategy:   In September 2000, Wisconsin Energy announced its Power the Future strategy to improve the supply and reliability of electricity in Wisconsin. As part of the Power the Future 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 Power the Future may be found below under Utility Operations and Environmental Compliance as well as in Item 7.

Other:   Bostco LLC (Bostco) is our non-utility subsidiary that develops and invests in real estate. As of December 31, 2005, Bostco had $40.9 million of assets.

Cautionary Factors Regarding Forward - Looking Statements:   Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, 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 as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described in Item 1A Risk Factors and under the heading Cautionary Factors in Item 7 of this report, other matters described under the heading Factors Affecting Results, Liquidity and Capital Resources in Item 7 of this report, and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) or otherwise described throughout this document. We disclaim any obligation to update these forward-looking statements.

We are the largest electric utility in the State of Wisconsin. We generate and distribute electric energy 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 Midwest Independent Transmission System Operator, Inc. (MISO) bid-based energy market (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.

See Selected Operating Data in Item 6 for certain electric utility operating information by customer class during the period 2001 through 2005.

We are authorized to provide retail electric service in designated territories in the State of Wisconsin, as established by indeterminate permits, certificates of public convenience and necessity 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 32.0 million megawatt hours (mwh) during 2005, a 2.6% increase from 2004. Approximately 0.4 million of megawatt-hour sales during 2005 were to Edison Sault. We had approximately 1,092,400 electric customers at December 31, 2005, an increase of 1.0% since December 31, 2004.

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 7.2% and 7.5% of our total electric utility energy sales during 2005 and 2004, respectively. The mines have notified us that they are disputing certain billings and they have placed the disputed amounts in escrow. In September 2005, the mines notified us that they have filed for formal arbitration related to this contract. 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. For further information, see Legal Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7 of this report.

Sales to Wholesale Customers:   During 2005, we sold wholesale electric energy to three municipally owned systems, two rural cooperatives and one municipal joint action agency located in the states of Wisconsin, Michigan and Illinois. We also made wholesale electric energy sales to 34 other public utilities and power marketers throughout the region under rates approved by the Federal Energy Regulatory Commission (FERC). Wholesale sales accounted for approximately 9.3% of our total electric energy sales and 5.5% of total electric operating revenues during 2005, compared with 9.7% of total electric energy sales and 4.1% of total electric operating revenues during 2004.

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 2005 electric peak demand obligation of 6,278 megawatts on August 9, 2005 and our all-time electric peak demand obligation of 6,376 megawatts on August 21, 2003. The summer period is the most relevant period for capacity planning purposes for us as a result of cooling load. In 2005 and prior, we were a member of the Mid-America Interconnected Network, Inc. (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. Because we must also adhere to Public Service Commission of Wisconsin (PSCW) guidelines requiring an 18% planning reserve margin

We had adequate capacity to meet all of our firm electric load obligations during 2005 and expect to have adequate capacity to meet all of our firm obligations during 2006. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7. For additional information regarding our generation facilities, see Item 2.

Prior to 2003, the nation's electric utility industry had been following a trend towards restructuring and increased competition. However, given electric reliability problems experienced in the east coast in the summer of 2003 and in the State of California in 2001 and 2002, which had previously restructured its electric industry framework, and given the current status of restructuring initiatives in regulatory jurisdictions where we primarily do business, we do not expect to be affected by a significant change in electric regulation in the next five years. The PSCW has been and remains focused on electric reliability infrastructure issues for the State of Wisconsin. The State of Michigan implemented electric retail access in 2002, and the FERC continues to support the voluntary formation of large Regional Transmission Organizations (RTO) such as MISO. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2005 as well as an estimate for 2006:

Wisconsin Energy's Power the Future plan, which is discussed further in Item 7, Power the Future, includes the addition of 2,320 megawatts of generating capacity over the next five years. These plants will be leased to Wisconsin Electric under long-term leases. The Power the Future plan includes two 545-megawatt natural gas units at our existing site in Port Washington, Wisconsin. The first natural gas unit was placed into service in July 2005. The second natural gas unit is expected to be operational in 2008. We Power has begun construction of two 615-megawatt coal units (of which We Power will own approximately a 515-megawatt share of each unit) at our existing site in Oak Creek, Wisconsin. 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 Power the Future plan 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 Unit 1, totaled 28.0 million megawatt hours during 2005 compared with 29.0 million megawatt hours during 2004 and 27.8 million megawatt hours during 2003. When compared with the

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 Power the Future plan are combined cycle facilities that are designed to run for longer durations and at a lower operating cost as compared to a peaking unit. The first unit at PWGS was placed into service in July 2005. We lease Unit 1 at PWGS from We Power.

Historically, the fuel costs for coal and nuclear generation are relatively stable as the fuel costs are under long-term contracts. In 2005, we entered into new coal contracts to replace certain contracts that expired during 2005. Coal and associated transportation services have seen greater volatility in pricing than typically experienced in these markets. Based on current market conditions, we expect coal and transportation costs to increase more significantly than our most recent historical trend.

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 keep pace with the demand for natural gas and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. Beginning in late 2003 and concurrent with the approval of the PSCW, we established hedging programs 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 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.

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 2006, 99% of our projected coal requirements of

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.

Coal Deliveries:   Approximately 82% of our 2006 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 Plants from Wyoming mines. Coal from Central Appalachia and Colorado mines is also transported via rail to Lake Erie or Lake Michigan transfer docks and delivered to the Valley and Milwaukee County Power Plants. Montana and Wyoming coal for Presque Isle Power Plant is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery. Central Appalachia and Colorado coal bound for Presque Isle Power Plant is shipped via rail to Lake Erie and Lake Michigan (Chicago) coal transfer docks, respectively, for lake vessel delivery to the plant.

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

Point Beach Nuclear Plant:   We own two 518-megawatt electric generating units at Point Beach Nuclear Plant (Point Beach) in Two Rivers, Wisconsin. We and Nuclear Management Company, LLC (NMC) filed an application with the U.S. Nuclear Regulatory Commission (NRC) in February 2004 to renew the operating licenses for both of our nuclear reactors for an additional 20 years. In December 2005, we received approval for license renewal from the NRC. The new operating licenses for Point Beach will expire in October 2030 for Unit 1 and in March 2033 for Unit 2. For additional information concerning Point Beach, see Factors Affecting Results, Liquidity and Capital Resources 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 megawatts. 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, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Nuclear Fuel Supply:   We purchase uranium concentrates (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

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 2007, with an option to extend the current contract through 2009. Contract negotiations through NMC are currently underway that would supply approximately 25% of the Point Beach requirements from 2010 to 2016.

Conversion:   We have 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 2005, the NMC conversion services contract was amended to supply approximately 20% of the Point Beach requirements through 2010. We are currently negotiating additional contracts for conversion services to meet approximately 50% of the Point Beach requirements through 2011.

Enrichment:   We effectively have one long-term contract and another contract through NMC that provide for 100% of the required enrichment services for the Point Beach reactors through the year 2006 and approximately 38% of the enrichment services requirements through 2009. Contract negotiations for additional enrichment services supply are currently underway that would supply the remainder of the Point Beach requirements through 2009.

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 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, 2005 to approximately $782.1 million. For additional information regarding decommissioning, see Note F -- Nuclear Operations in the Notes to Consolidated Financial Statements in Item 8.

Nuclear Plant Insurance:   For information regarding nuclear plant insurance, see Factors Affecting Results, Liquidity and Capital Resources in Item 7 and Note F -- Nuclear Operations in the Notes to Consolidated Financial Statements in Item 8.

Our hydroelectric generating system consists of thirteen operating plants with a total installed capacity of approximately 88 megawatts and a dependable capability of approximately 57 megawatts. Of these thirteen plants, twelve are licensed by the FERC. The thirteenth plant, with an installed generating capacity of approximately 2 megawatts, does not require a license. Twelve licensed plants, representing a total of 86 megawatts of installed capacity, have long-term licenses from the FERC.

Our natural gas-fired generation consists of four operating plants with a dependable capability of approximately 888 megawatts. In addition, in July 2005, we added 545-megawatts of leased natural gas-fired generation when the first unit at PWGS became operational. The second 545-megawatt 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.

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, as backup for ignition at the Pleasant Prairie Power Plant and as a backup fuel for the natural gas-fired turbines which have interruptible transportation. Our oil-fired generation has a dependable capability of approximately 275 megawatts. 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.

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 with unaffiliated companies over the next five years:

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. The energy costs for the balance of the commitments are tied to the costs of natural gas.

American Transmission Company:   Effective January 1, 2001, we transferred all of our electric utility transmission assets to American Transmission Company LLC (ATC) in exchange for an ownership interest in this new company. Joining ATC is consistent with the FERC's Order No. 2000, designed to foster competition, efficiency and reliability in the electric industry.

ATC is owned by the utilities that contributed facilities or capital in accordance with 1999 Wisconsin Act 9. As of December 31, 2005, we owned approximately 29.4% of ATC. We anticipate that our ownership will be reduced to approximately 26% by December 31, 2006 as other owners contribute transmission assets to ATC.

ATC's sole business is to provide reliable, economic electric transmission service to all customers in a fair and equitable manner. Specifically, ATC plans, constructs, operates, maintains and expands transmission facilities it owns to provide for adequate and reliable transmission of electric power. 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 the 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 have contracted to provide, at cost, services required by ATC. Services include transmission line and substation operation and maintenance, engineering, project, real estate, environmental, supply chain, control center and miscellaneous services. The annual cost of the services provided by us was approximately $20 million, $21 million

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.

Wisconsin Energy's Power the Future plan includes a commitment to significantly increase the amount of renewable energy generation we utilize beyond that required by Wisconsin law. Our target is to provide 5% of our retail electric sales in Wisconsin from renewable energy resources by the year 2011. In addition, we have an "Energy For Tomorrow®" renewable energy program to provide our customers the opportunity to purchase energy from renewable resources.

Wisconsin's public benefits legislation requires that for 2006, retail energy providers supply 1.2% of a three year average of their Wisconsin retail electric sales from renewable energy. The required minimum percentage increases to 2.2% by the year 2011. For more information about public benefits see Regulation below.

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 to 200 megawatts at a cost in the range of $250 to $320 million. We plan to file the necessary regulatory and environmental applications in 2006. We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.

We are authorized to provide retail gas distribution service in designated territories in the State of Wisconsin, as established by indeterminate permits, certificates of public convenience and necessity, 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.

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.

See Selected Operating Data in Item 6 for selected gas utility operating information by customer class during the period 2001 through 2005.

Total gas therms delivered, including customer-owned transported gas, were approximately 902.4 million therms during 2005, an 8.1% increase compared with 2004. At December 31, 2005, we were transporting gas for approximately 364 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 39% of the total volumes delivered during 2005, 34% during 2004, and 35% during 2003. We had approximately 446,400 gas customers at December 31, 2005, an increase of approximately 2.0% since December 31, 2004.

Our maximum daily send-out during 2005 was 656,249 dekatherms on January 17, 2005. A dekatherm is equivalent to ten therms or one million British thermal units.

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 therm deliveries of natural gas to grow at an annual rate of approximately 0.9% for our gas operations over the five-year period ending December 31, 2010. 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 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 where it is used. 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 future ability to maintain our present 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.

We have been able to meet our contractual obligations with 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 spring and summer months and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity than would otherwise be necessary, and can purchase gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

We also maintain high deliverability 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, which can reduce long-line supply.

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 gas cost incentive mechanisms 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 gas cost recovery mechanism. During 2005, 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 gas cost recovery (incentive) mechanism.

Guardian Pipeline:   Wisconsin Energy has a one-third interest in Guardian Pipeline L.L.C. (Guardian). We do not have an ownership interest in Guardian. Two unaffiliated companies also have one-third interests. Guardian owns an interstate natural gas pipeline from the Joliet, Illinois market hub to southeastern Wisconsin that is designed to serve the growing demand for natural gas in Wisconsin and Northern Illinois. Guardian pipeline began commercial operation in early December 2002. Currently, Guardian has firm transmission service agreements to transport 98% of its 750,000 dekatherms per day pipeline design capacity. Together, we and Wisconsin Gas have committed to purchase 650,000 dekatherms (approximately 87% of the pipeline's total capacity) per day of capacity on the pipeline over a long-term contract that expires in December 2012.

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 2005, the steam utility had $23.4 million of operating revenues from the sale of 2,908 million pounds of steam compared with $22.0 million of operating revenues from the sale of 2,869 million pounds of steam during 2004. As of December 31, 2005 and 2004, steam was used by approximately 460 customers for processing, space heating, domestic hot water and humidification.

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

We were an exempt holding company under Section 3(a)(1) of the Public Utility Holding Company Act of 1935, as amended (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 of 2005 (Energy Policy Act). The Energy Policy Act repealed PUHCA 1935 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005), transferring jurisdiction over holding companies from the SEC to the FERC. We will be required to notify the FERC of our status as a holding company by reason of our ownership interest in ATC and to seek from the FERC the 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 the FERC to review proposed mergers and the acquisition of generation facilities, changes the 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 the FERC, which will establish mandatory electric reliability standards, replacing the current voluntary standards developed by the North American Electric Reliability Council, 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 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 the FERC. We are subject to regulation of the 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, 2005.

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.

Operation and construction relating to our Point Beach Nuclear Plant are subject to regulation by the NRC. Our operations are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Natural Resources and the Michigan Department of Environmental Quality.

Public Benefits:   Public benefits legislation was included in 1999 Wisconsin Act 9. The law created new funding which is adjusted annually to be collected by all electric utilities and remitted to the Wisconsin Department of

This law also requires that for 2006, retail energy providers supply 1.2% of a three year average of their Wisconsin retail electric sales from renewable energy. The required minimum percentage increases to 2.2% by the year 2011.

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 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 $153 million in 2005 compared with $78 million in 2004. Expenditures incurred during 2005 primarily included costs associated with the installation of pollution abatement facilities at our power plants. These expenditures are expected to approximate $83 million during 2006, reflecting nitrogen oxide (NO_x), sulfur dioxide (SO₂) and other pollution control equipment needed to comply with various rules promulgated by the EPA.

We estimate that our operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $40 million during 2005 and $52 million during 2004.

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 against us.

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:

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, discussion is 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. Future costs for remediation of this site are estimated to be approximately $1.0 million.

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. Future costs for remediation are estimated to be approximately $1.5 million and involve reconfiguration of the site and construction of a new cap, which will be accomplished as a part of site upgrades needed to facilitate construction of the new power plants.

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.

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

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 for additional information concerning the Clean Water Act.

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, 2005, we had 4,653 total employees, of which 3,207 were represented under labor agreements. We had the following employees represented under labor agreements with the following bargaining units as of December 31, 2005:

We estimate that approximately 88% of our electric revenues are regulated by the PSCW, 6% are regulated by the MPSC and the balance of our electric revenues is regulated by the 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 maintain our current authorized rates of return.

Under Wisconsin Energy's Power the Future strategy, we expect to meet a significant portion of our future generation needs through the leasing of two 545-megawatt natural gas-fired generating units at the Port Washington Generating Station and two 615-megawatt coal-fired generating units (of which We Power will own a 515-megawatt share) to be located adjacent to our Oak Creek Power Plant. These new generating facilities are being constructed by We Power and will be leased to us under long-term leases. The first of these four units was placed into service in July 2005.

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 are required to seek FERC authorization to lease from We Power the three Power the Future units that are currently being constructed by We Power. We are unable to determine at this time the magnitude of this new regulatory requirement on the Power the Future plan, if any.

We are subject to extensive environmental regulations relating to, among other things, air emissions such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates and mercury, water discharges and management of hazardous and solid waste. 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.

Existing environmental regulations may be revised or new laws or regulations may be adopted which could result in significant additional expenditures and operating restrictions on our facilities. In the event we are not able to

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. The incurrence of a material environmental liability could have a significant adverse effect on our results of operations and financial condition.

We own two 518-megawatt nuclear electric generating units at the Point Beach site. The units are operated by NMC, a joint venture of Wisconsin Energy and affiliates of other unaffiliated utilities. During 2005, our nuclear generating units provided 20% of our net electric energy supply. 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; the threat of possible terrorist attacks; 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.

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 which approximate 20-year averages. Below normal temperatures during the summer cooling season, and to a lesser extent, above normal temperatures during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, above normal temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.

Significant increases in the cost of natural gas affect our electric and gas utility operations. Natural gas costs have increased significantly, both 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, and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. 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 Port Washington Generation Station Unit 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 gas cost recovery mechanisms, 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. We have experienced reduced usage of natural gas by our residential customers in 2005 and expect this to continue during the 2006 winter heating season. 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 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 which 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 megawatt hour 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 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.

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 which could result in decreased earnings and cash flow. In addition, regional economic conditions also impact our collections of accounts receivable.

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 the ability of us 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 significantly adversely affected.

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. However, the Energy Policy Act repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to the FERC. We will be required to notify the FERC of our status as a holding company and to seek from the FERC the exempt status similar to that held under PUHCA 1935. If we are unable to obtain exempt status from the FERC, we may become subject to increased regulation as a holding company by the FERC.

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. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen 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.

The FERC continues to support the existing RTOs which 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 locational marginal price (LMP) which reflects the market price for energy. As a participant in the new 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 financial transmission rights (FTRs). FTRs are allocated to market participants by MISO. We are presently operating under an FTR allocation that will be in effect through May 31, 2006. To date, our unhedged congestion charges have not been material. However, there can be no assurance that we will be granted an adequate level of FTRs in the future to avoid material unhedged congestion charges.

None.

As of December 31, 2005, we own the following generating stations with dependable capabilities during 2005 as indicated.

Effective July 2005, we began leasing PWGS Unit 1, a 545-megawatt natural gas-fired generation unit, from We Power under a 25 year lease. In addition, we have a power purchase contract with an unaffiliated independent power producer. The contract is for 236 megawatts of firm capacity from a gas-fired cogeneration facility that expires in 2022.

As of December 31, 2005, our electric utility operated approximately 21,900 pole-miles of overhead distribution lines and 21,700 miles of underground distribution cable, as well as approximately 390 distribution substations and 272,200 line transformers.

As of December 31, 2005, our gas distribution system included approximately 9,100 miles of 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 which 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 dekatherms per day. We also have a propane air system for peaking purposes. This propane air system will provide approximately 2,000 dekatherms per day of supply to the system. Where distribution lines and services and gas distribution mains

As of December 31, 2005, 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.

We own various office buildings and service centers throughout our service area.

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 Comprehensive Environmental Response, Compensation and Liability Act (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. We have not been named as a potentially responsible party at this time. Although we have not accepted responsibility for costs of any sort related to the property, remediation cost estimates and reserves continue to be 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.

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

Used Nuclear Fuel Storage and Removal:   See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 for information concerning the United States Department of Energy's breach of a contract with us that required the Department of Energy to begin permanently removing used nuclear fuel from Point Beach Nuclear Plant 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 its 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 have filed an appeal in this decision. In May 2005, a stray voltage

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 its 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 affects. 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.

No matters were submitted to a vote of our security holders during the fourth quarter of 2005.

The names, ages at December 31, 2005 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 a limited liability company.

Gale E. Klappa. Age 55.

• 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 59.

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

Stephen P. Dickson. Age 45.

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

Frederick D. Kuester. Age 55.

• 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 39.

• 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 49.

• 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. Vice President of Customer Services from 1995 to 2001.
• 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 58.

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

In addition, effective January 3, 2006, James C. Fleming was appointed Executive Vice President of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

James C. Fleming. Age 60.

• Wisconsin Energy Corporation - Executive Vice President since January 2006.
• Wisconsin Electric Power Company - Executive Vice President since January 2006.
• Wisconsin Gas LLC - 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.

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.

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 information regarding restrictions on our ability to pay dividends, see Note N -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.