WISCONSIN ELECTRIC POWER CO - Annual Report: 2006 (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, 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):

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.

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

Regulatory Commission, for the transaction; and our ability to retain the assets for the benefit of customers in the non‑qualified decommissioning trust.

• 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.

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".

PTF Strategy:   In September 2000, Wisconsin Energy announced its PTF strategy 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.

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.

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.

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.

Wisconsin Energy's PTF strategy, which is discussed further in Item 7, includes the addition of 2,320 MW of generating capacity through 2010. The PTF strategy includes 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 PTF strategy 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.

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.

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.

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

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

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.

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.

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.

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.

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.

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:

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.

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.

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.

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

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.

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.

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 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.

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

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.

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

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.

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 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.

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 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.

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.

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 NO_x, 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.

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.

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.

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.

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 CWA.

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:

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.

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 PTF units that are currently being constructed by We Power. We received authorization from FERC for these leases in December 2006.

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.

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.

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.

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.

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.

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 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 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 that 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 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.

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.

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.

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

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.

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.