WISCONSIN ELECTRIC POWER CO - Annual Report: 2007 (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, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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                                 Non-accelerated filer [X] (Do not                    Smaller reporting company [  ]
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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, 2007 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, 2008):

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 25, 2008, are incorporated by reference into Part III hereof.

Certain statements contained in this report are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, 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. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms.

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

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, 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; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; or inflation rates.

• Increased competition in our electric and gas markets and continued industry consolidation.

• Timing, resolution and impact of pending and future rate cases and negotiations, including recovery for new investments as part of Wisconsin Energy's PTF strategy, environmental compliance, transmission service, fuel costs and costs associated with the implementation of the MISO Energy Markets.

• Regulatory factors such as changes in rate-setting policies or procedures; changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; and the siting approval process for new generation and transmission facilities and new pipeline construction.

• Factors affecting the economic climate in our service territories such as customer growth; customer business conditions, including demand for their products and services; and changes in market demand and demographic patterns.

• Factors which impede execution of Wisconsin Energy's PTF strategy, including receipt of necessary state and federal regulatory approvals and permits; timely and successful resolution of legal challenges, including current challenges to the WPDES permit for the Oak Creek expansion; opposition to siting of new generating facilities; the adverse interpretation or enforcement of permit conditions by the permitting agencies; and obtaining the investment capital from outside sources necessary to implement the strategy.

• The impact of recent and future federal, state and local legislative and regulatory changes, including electric and gas industry restructuring initiatives; implementation of the Energy Policy Act; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; and changes in the application of existing laws and regulations.

• The cost and other effects of legal and administrative proceedings, settlements, investigations, 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 our credit ratings.

• The investment performance of our pension and other post-retirement benefit plans.

• The effect of accounting pronouncements issued periodically by standard setting bodies.

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

• Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters.

• The cyclical nature of property values that could affect our real estate investments.

• Other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents, including the risk factors set forth in Item 1A of this report.

Wisconsin Electric Power Company expressly disclaims 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 1,109,500 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 457,200 gas customers in Wisconsin and approximately 470 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, 2007, Bostco had $38.2 million of assets.

Our annual and periodical filings to the SEC are available, free of charge, through Wisconsin Energy's 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 Energy Markets 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 Energy Markets.

Our electric energy sales to all classes of customers totaled approximately 32.7 million MWh during 2007 and approximately 31.4 million MWh during 2006. We had approximately 1,109,500 electric customers at December 31, 2007 and 1,102,200 electric customers at December 31, 2006.

Electric Sales Growth:   We presently anticipate total retail and municipal electric kWh sales will grow at an annual rate of 1.0% to 1.5% over the next five years. This estimate excludes our largest customer, two iron ore mines 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 had special negotiated power-sales contracts with these mines that expired in December 2007. The combined electric energy sales to the two mines accounted for 6.4% and 6.3% of our total electric utility energy sales during 2007 and 2006, respectively. In 2005, the mines notified us that they were disputing certain billings and placed the disputed amounts in escrow. In May 2007, we entered into a settlement agreement with the two iron ore mines. The settlement was a full and complete resolution of all claims and disputes between the parties for electric service rendered by us under the power purchase agreements through March 31, 2007. The MPSC approved the settlement in May 2007. Pursuant to the settlement, the mines paid us approximately $9.0 million and we released to the mines all funds held in escrow. The settlement also provided a mutually satisfactory pricing structure through December 31, 2007. Beginning January 1, 2008, the mines became eligible to receive electric service from us in accordance with tariffs approved by the MPSC.

Sales to Wholesale Customers:   During 2007, 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 11.8% of our total electric energy sales and 7.3% of total electric operating revenues during 2007, compared with 10.4% of total electric energy sales and 5.7% of total electric operating revenues during 2006.

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, 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 RFC, a successor council encompassing most of the East Central Area Reliability Council and Mid-Atlantic Area Council, and a portion of MAIN. The RFC has approved reliability standards, which set forth the methodology for establishing planning reserve requirements and require the formation of PRSG. We are a member of the Midwest PRSG, which was formed in June 2007 to establish planning reserve requirements. We must also adhere to PSCW guidelines requiring an 18% planning reserve margin; however, in November 2007, the PSCW opened a new docket to review the 18% planning reserve margin requirement. We cannot at this time predict the outcome of this docket and its potential impact on the current 18% requirement. The MPSC has not established guidelines in this area.

We had adequate capacity to meet all of our firm electric load obligations during 2007 and expect to have adequate capacity to meet all of our firm obligations during 2008. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Our electric supply strategy is to provide our customers with a diverse fuel mix that is expected to maintain a stable, reliable and affordable supply of electricity. We supply electricity to our customers from power plants that we own. We supplement our internally generated power supply with long-term power purchase agreements and through spot purchases in the MISO Energy Markets.

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

Wisconsin Energy's PTF strategy, which is discussed further in Item 7, includes the addition of 2,320 MW of generating capacity from 2005 through 2010. The first plant, a natural gas combined cycle unit, providing 575 MW of dependable capability, went on line in 2005. The second 545 MW unit is expected to go on line in the second quarter of 2008. Under Wisconsin Energy's PTF plan, We Power expects to have 515 MW of dependable capability coming in service in 2009 related to the first coal unit. The second coal unit is expected to provide us with 515 MW of dependable capability in 2010. In addition, we expect to have 145 MW of wind generation coming on line during 2008, of which only 32 MW is dependable capability.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2007 as well as an estimate for 2008.

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

Historically, the fuel costs for coal have been under long-term contracts, which helped with price stability. In 2006, we entered into new long-term 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 which are reflected in the form of fuel surcharges on rail transportation.

The costs for natural gas and purchased power, which is primarily natural gas-fired, are 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. 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 2007, 2006 and 2005 average costs of natural gas and purchased power shown above. In addition, concurrent with the Point Beach sale, our purchased power costs also reflect the long-term power purchase agreement with the buyer for all of the energy produced by Point Beach.

Our coal-fired generation consists of 19 generating units as of December 31, 2007. OC 1 and OC 2 are expected to be operational in 2009 and 2010, respectively, each with a total lease-guaranteed capacity of 615 MW, of which 515 MW will represent our approximate 83% share in these units.

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 2008, 100% of our projected coal requirements of 12.3 million tons are under contracts which are not tied to 2008 market pricing fluctuations. Our coal-fired generation consists of six operating plants with a dependable capability of approximately 3,247 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 87% of our 2008 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 the 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 the 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 Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.

Point Beach:   Prior to September 28, 2007, we owned two 518 MW electric generating units at Point Beach in Two Rivers, Wisconsin. On September 28, 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. Pursuant to the terms of the sale agreement, the buyer purchased Point Beach, its nuclear fuel, associated inventories and assumed the obligation to decommission the plant.

A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, we are purchasing all of the energy produced by Point Beach. The power purchase agreement extends through 2030 for Unit 1 and 2033 for Unit 2. Based on the agreement, we will be paying the buyer a predetermined price per MWh for energy delivered. For additional information on the sale of Point Beach, see Nuclear Operations under Factors Affecting Results, Liquidity and Capital Resources in Item 7 of this report.

Nuclear Management Company:   Prior to the Point Beach sale, our affiliate, WEC Nuclear Corporation, had a partial ownership in NMC. NMC held the operating licenses for Point Beach. Upon the sale of Point Beach, NMC transferred the operating licenses to the buyer and the relationship with NMC was terminated.

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.

For further information on the sale of Point Beach, see Note F -- Nuclear Operations in the Notes to Consolidated Financial Statements.

Our natural gas-fired generation consists of five operating plants with a dependable capability of approximately 1,475 MW at December 31, 2007. 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 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 had a dependable capability of approximately 257 MW at December 31, 2007. 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, 2007. 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 hold development rights for two wind farm projects and began construction of the first project in 2007. Additional information on wind generation is provided in Factors Affecting Results, Liquidity and Capital Resources -- Other Utility Rate Matters -- Wind Generation in Item 7.

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. The following table identifies our power purchase commitments at December 31, 2007 with unaffiliated parties for the next five years:

Approximately 1,000 MW per year relates to the Point Beach long-term power purchase agreement. Under this agreement, we will pay a predetermined price per MWh for energy delivered according to a schedule included in the agreement. The majority of the balance of these power purchase 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. 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 during the second quarter of 2008, with a lease-guaranteed capacity of 545 MW. OC 1 and OC 2 are expected to be operational in 2009 and 2010, respectively, each with a total lease-guaranteed capacity of 615 MW, of which 515 MW will represent our approximate 83% share in these units.

American Transmission Company:   ATC owns, maintains, monitors and operates electric transmission systems 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. MISO maintains operational control of ATC's transmission system, and we are a non-transmission owning member and customer of MISO.

We owned approximately 23.6% and 25.8% of ATC as of December 31, 2007 and 2006, respectively. Our ownership has decreased in recent years 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 bid-based energy markets, the MISO Energy Markets, which were implemented on April 1, 2005. For further information on MISO and the MISO Energy Markets, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Electric Hedging Program:   We purchase some of the electricity needed to satisfy our current sales obligations in the MISO Energy Markets. Due to volatility in the price of market-based energy, we face potential financial exposure. We have PSCW approval to hedge up to 75% of a future month's predicted electricity need. This plan seeks to manage market price risk, as well as reduce price risks related to forced outages.

We also seek to mitigate the risk of price increases in coal transportation costs for coal used in our coal-fired generating facilities. The coal transportation price changes are tied to changes in a diesel fuel price index. Therefore, we generally use financial heating oil contracts to mitigate this risk. This approach is similar to the way we currently manage our natural gas supply prices. See "Hedging Gas Supply Prices" below for information on our natural gas hedging program.

We have committed 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, which 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 2003 to 2007 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 883.0 million therms during 2007, an 8.7% increase compared with 2006. As of December 31, 2007, we were transporting gas for approximately 358 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 38% of the total volumes delivered during 2007, 37% during 2006 and 39% during 2005. We had approximately 457,200 gas customers as of December 31, 2007, an increase of approximately 1.0% since December 31, 2006. Our peak daily send-out during 2007 was 699,630 Dth on February 5, 2007.

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 generation 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, 2012 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. A number 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 spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage 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. In 2007, we continued the plan started in 2006 to enter into gas purchase contracts which allow us to reduce gas inventory while maintaining supply to meet daily and seasonal demands.

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 rate payers, 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 2007, 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) to rate payers 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:   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 its 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. In December 2007, FERC issued a CPCN to Guardian authorizing its related extension project, which is expected to be operational in November 2008.

The following table shows certain gas utility operating statistics from 2003 to 2007 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 2007, the steam utility had $35.1 million of operating revenues from the sale of 2,965 million pounds of steam compared with $27.2 million of operating revenues from the sale of 2,812 million pounds of steam during 2006. As of December 31, 2007 and 2006, steam was used by approximately 470 and 460 customers, respectively, 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 PUHCA 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, repealed PUHCA 1935, making electric utility industry consolidation more feasible, authorized FERC to review proposed mergers and the acquisition of generation facilities, changed the FERC regulatory scheme applicable to qualifying co-generation facilities and modified 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 established mandatory electric reliability standards, replacing the current voluntary standards developed by the North American Electric Reliability Corporation, and has 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, electric reliability requirements 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, 2007.

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, which 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 $31 million in 2007 compared with $79 million in 2006. Expenditures incurred during 2007 primarily included costs associated with the installation of pollution abatement facilities at our power plants. These expenditures are expected to approximate $119 million during 2008, 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 $54 million during 2007 and $49 million during 2006.

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 Oak Creek expansion. Currently there is a temporary cap installed, which is 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.

See the caption, "We may face significant costs to comply with the regulation of greenhouse gas emissions" under Item 1A Risk Factors in this report.

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:   As of December 31, 2007, we had 4,321 total employees, of which 2,887 were represented under labor agreements with the following bargaining units:

We are obligated in good faith to comply with all 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 and other amounts, which could materially and adversely affect our results of operations and financial condition.

We estimate that within our regulated energy segment, approximately 88% 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 costs and expenses and to maintain our current authorized rates of return.

We believe we have obtained the necessary permits, approvals and certificates for our existing operations and that our respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to us cannot be predicted. Changes in regulation, interpretations of regulations or the imposition of additional regulations could influence our operating environment and may result in substantial compliance costs.

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. PWGS 2 is expected to go into service in the second quarter of 2008. OC 1 and OC 2 are scheduled to go into service in 2009 and 2010, respectively.

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, legal challenges and appeals to granted permits, including the WPDES permit granted in connection with the Oak Creek expansion, changes in applicable law or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies, other governmental actions and events in the global economy.

We are subject to extensive environmental regulations affecting our past, present and future operations relating to, among other things, air emissions such as CO_2, SO₂, NO_x, 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. In addition to requiring capital expenditures, 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.

Global warming is increasingly a concern for the energy industry. Although there continues to be significant debate regarding the extent of global warming and the impact of human activity, federal and state legislative proposals have been introduced to regulate the emission of greenhouse gases, particularly CO₂. In addition, there have been international efforts seeking legally binding reductions in emissions of greenhouse gases.

We believe it is likely that future governmental legislation and/or regulation may require us either to limit greenhouse gas emissions from our operations or to purchase allowances for such emissions. However, we cannot predict what form these future regulations will take, the stringency of the regulations or when they will become effective. Several bills have been introduced in the United States Congress that would compel CO₂ emission reductions. While none have yet been passed by Congress, the competing bills remain pending. Proposals under consideration include limitations on the amount of greenhouse gases that can be emitted (so called "caps") together with systems of trading permitted emissions capacities. This type of system could require us to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase costly allowances for such emissions. Emissions also could be taxed independently of limits.

In April 2007, the United States Supreme Court concluded that the EPA already has authority to regulate CO₂ emissions under the CAA. As a result, the EPA is now reconsidering whether to regulate motor vehicle emissions of CO₂ under the CAA. Any decision to regulate motor vehicle CO₂ emissions under the CAA may have significant implications for stationary sources of CO₂ emissions including fossil fuel fired electric generating plants.

At the state level, on April 5, 2007, the Governor of Wisconsin signed Executive Order 191 creating the Task Force on Global Warming to bring together a group of Wisconsin business, industry, government, energy and environmental leaders to examine the effects of, and solutions to, global warming in Wisconsin. We are actively participating in the Task Force. The purpose of the Task Force is to discuss and analyze possible solutions to global warming challenges that pose a threat to Wisconsin's economic and environmental health. The Task Force is charged with creating a state plan of action to deliver to the Governor to reduce greenhouse gas emissions in Wisconsin. The work of the Governor's Task Force is ongoing.

In addition, on November 14, 2007, the Governor of Michigan signed Executive Order 2007-42 creating the Michigan Climate Action Council, which is similar in scope and purpose to the Task Force on Global Warming in Wisconsin.

The Governors of both Michigan and Wisconsin have signed on to the "Midwestern Greenhouse Gas Reduction Accord" and the associated "platform" document developed through the Midwest Governor's Association. The stated goal of the platform is to "maximize the energy resources and economic advantages and opportunities of Midwestern states while reducing emissions of atmospheric CO₂ and other greenhouse gases." Certain elements of this agreement have the potential to impact the cost and nature of our operations in Wisconsin and Michigan.

These state and regional initiatives could lead to legislation and regulation of greenhouse gas emissions that could be implemented sooner and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that is adopted.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with any future legislation and/or regulation that requires a reduction in greenhouse gas emissions, or that recovery will not be delayed or otherwise conditioned. Future legislation and/or regulation designed to reduce greenhouse gas emissions could make some of our electric generating units uneconomic to maintain or operate and could affect future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.

We continue to monitor the legislative and regulatory developments in this area. Although we expect the regulation of greenhouse gas emissions to have a material impact on our operations and rates, we believe it is premature to attempt to quantify the possible costs of the impacts.

Our electric generation and gas transportation facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities, including cyber terrorism. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, purchase 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 and 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 which 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 in recent years because the supply of natural gas 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.

We 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. 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 those fuels as well. We bear the regulatory risk for the recovery of fuel and purchased power costs when those costs are higher than the base rate established in our rate structure. For 2008, we will be unable to prospectively recover fuel and purchased power costs until the costs exceed a pre-established annual band.

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 expose 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 power purchases through other potentially higher cost generating resources in the MISO Energy Markets. 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 cost of providing non-contributory defined benefit pension plans are dependent upon a number of factors resulting from actual plan experience and assumptions concerning the future, such as earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions to be made to the plans. Changes made to the plans may also impact current and future pension costs. We expect to contribute approximately $43.6 million to fund the pension plans in 2008. Depending upon the growth rate of the pension investments over time and depending upon the other factors impacting our costs as listed above, we could be required to contribute significant additional amounts in the future to fund our plans. These additional funding obligations could have a material adverse impact on our cash flows, financial condition or results of operations.

Our electric and gas utility businesses are impacted by the economic cycles of the customers we serve. In the event regional economic conditions or the demand for products produced in our service area decline, we may experience reduced demand for electricity and/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, preferred stock and equity contributions from our parent, Wisconsin Energy. Recently, certain investment banks announced the adoption of the "Carbon Principles," a set of guidelines designed to help the investment banks assess environmental risk in connection with the financing of new fossil fuel power plants. The Carbon Principles are expected to be employed in conjunction with an "Enhanced Environmental Diligence Process" in evaluating whether to participate in the financing of such projects.

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 Energy Markets on April 1, 2005. The MISO Energy Markets 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 Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system.

None.

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