ITEM 1.
BUSINESS
INTRODUCTION
Wisconsin Energy Corporation was incorporated in the State of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.
We conduct our operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. Our primary subsidiaries are Wisconsin Electric, Wisconsin Gas, Edison Sault and We Power.
Utility Energy Segment:
Our utility energy segment consists of: Wisconsin Electric, Wisconsin Gas and Edison Sault. We serve approximately 1,137,800 electric customers in Wisconsin and the Upper Peninsula of Michigan. We have approximately 1,056,400 gas customers in Wisconsin, 465 steam customers in metropolitan Milwaukee, Wisconsin, and 3,060 water customers in suburban Milwaukee, Wisconsin. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies".
Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric the new generating capacity included in our PTF strategy. See below and in Item 7 for more information on PTF.
Discontinued Operations: In September 2006, we sold 100% of our membership interests in Minergy Neenah LLC. Previously, Minergy Neenah LLC's operations were included in Corporate and Other.
PTF Strategy: In September 2000, we announced our PTF strategy to improve the supply and reliability of electricity in Wisconsin. As part of our PTF strategy, we are: (1) investing in new natural gas-fired and coal-fired electric generating facilities, (2) upgrading Wisconsin Electric's existing electric generating facilities and (3) investing in upgrades of our existing energy distribution system. Also, as part of this strategy, we announced and began implementing plans to divest non-core assets and operations in our non-utility energy segment and to reduce our real estate operations. Additional information concerning PTF may be found below under Non-Utility Energy Segment, as well as in Item 7.
For further financial information about our business segments, see Results of Operations in Item 7 and Note Q -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.
Our annual and periodical filings with the SEC are available, free of charge, through our Internet website www.wisconsinenergy.com. These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.
UTILITY ENERGY SEGMENT
ELECTRIC UTILITY OPERATIONS
Our electric utility operations consist of the electric operations of Wisconsin Electric and Edison Sault. Wisconsin Electric, which is the largest electric utility in the State of Wisconsin, generates and distributes electric energy in a territory in southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Edison Sault generates and distributes electric energy in a territory in the eastern Upper Peninsula of Michigan.
Wisconsin Electric and Edison Sault participate in the MISO Energy Markets which determines how our generating units are dispatched and how we buy and sell power. For further information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.
Electric Sales
Our electric energy sales to all classes of customers, excluding intercompany sales between Edison Sault and Wisconsin Electric, totaled approximately 31.9 million MWh during 2008 and approximately 33.0 million MWh during 2007. We had approximately 1,137,800 electric customers at December 31, 2008 and 1,132,500 electric customers at December 31, 2007.
Wisconsin Electric: Wisconsin Electric is 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. Wisconsin Electric also sells wholesale electric power within the MISO Energy Markets.
Edison Sault: Edison Sault is authorized to provide retail electric service in certain territories in the state of Michigan pursuant to franchises granted by municipalities. Edison Sault also provides wholesale electric service under contract with one rural cooperative.
Electric Sales Growth: We presently anticipate total retail and municipal electric kWh sales of our utility energy segment will grow at an annual rate of 0.25% to 0.75% over the next five years. This estimate assumes normal weather and excludes our largest customers, two iron ore mines. We also anticipate that our peak electric demand will grow at an annual rate of 1.0% to 1.5% over the next five years.
Sales to Large Electric Retail Customers: Wisconsin Electric provides 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. Edison Sault provides electric service to industrial accounts in the paper, crude oil pipeline and limestone quarry industries, as well as to several state and federal government facilities.
Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan. The combined electric energy sales to the two mines accounted for 6.5% and 6.3% of our total electric utility energy sales during 2008 and 2007 respectively. Effective January 1, 2008, the mines became eligible to receive electric service from Wisconsin Electric in accordance with tariffs approved by the MPSC. Prior to this, Wisconsin Electric had special negotiated power-sales contracts with these mines.
Sales to Wholesale Customers: During 2008, Wisconsin Electric 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. Wholesale electric energy sales by Wisconsin Electric were also made to nine other public utilities and power marketers throughout the region under rates approved by FERC. Edison Sault sold wholesale electric energy to one rural cooperative during 2008. Wholesale sales accounted for approximately 9.9% of our total electric energy sales and 3.6% of total electric operating revenues during 2008, compared with 10.9% of total electric energy sales and 6.5% of total electric operating revenues during 2007.
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, Wisconsin Electric was 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, Wisconsin Electric 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. Wisconsin Electric is a member of the Midwest PRSG which was formed in June 2007 to establish planning reserve requirements. As a member of the Midwest PRSG, Wisconsin Electric was required to adhere to PSCW guidelines requiring an 18% planning reserve margin. In November 2007, the PSCW opened a new docket to review the 18% planning reserve margin requirement. In October 2008, the PSCW issued an order lowering the planning reserve margin requirement from 18% to 14.5% effective for planning year two and each year beyond, and the MISO calculated the planning reserve margin for the first planning year 2009-2010. The MPSC has not yet established guidelines in this area.
We had adequate capacity to meet all of our firm electric load obligations during 2008 and expect to have adequate capacity to meet all of our firm obligations during 2009. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.
Electric Supply
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 a significant amount of electricity to our customers from power plants that we own. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed later in this report, and through spot purchases in the MISO Energy Markets.
Our installed capacity by fuel type for the years ended December 31, is shown below:
(a)
Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. The values were established by test and may change slightly from year to year.
(b)
Concurrent with the sale of Point Beach, Wisconsin Electric entered into a power purchase agreement with the buyer to purchase all of the energy produced by Point Beach until 2030 for Unit 1 and 2033 for Unit 2.
(c)
The increase in 2008 as compared to 2007 reflects PWGS 2, which has a dependable capability of 545 MW, going inservice during May 2008.
(d)
The dual-fueled 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.
(e)
Includes hydroelectric and wind generation. For purposes of measuring dependable capability, the 145 MW Blue Sky Green Field wind project has a dependable capability of 29 MW.
Our PTF strategy, which is discussed further in Item 7, includes the addition of 2,320 MW of generating capacity from 2005 through 2010. Our first two plants, PWGS 1 and PWGS 2, which are both natural gas combined cycle units with a dependable capability of 545 MW each, were placed in service in July 2005 and May 2008, respectively. Under our PTF plan, we expect to have 515 MW of dependable capability coming in service in late 2009 related to our first coal unit. The second coal unit is expected to provide us with 515 MW of dependable capability in 2010.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2008, as well as an estimate for 2009:
(a)
Beginning in 2007, purchased power increased and nuclear generation decreased due to the sale of Point Beach and the entry into the associated power purchase agreement with the buyer.
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. 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.
Natural gas costs are volatile, which impacts the cost of natural gas-fired generation and purchased power. Beginning in late 2003 and concurrent with the approval by 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 2008, 2007 and 2006 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.
Coal-Fired Generation
Coal Supply: We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming and Colorado as well as from various other western mines. During 2009, 100% of our projected coal requirements of 11.6 million tons are under contracts which are not tied to 2009 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 86% of our 2009 coal requirements are expected to be delivered by Wisconsin Electric-owned or leased unit trains. The unit trains will transport coal for the Oak Creek, Pleasant Prairie and Edgewater Power Plants from Wyoming mines. Coal from Colorado mines is also transported via rail to Lake Superior or Lake Michigan transfer docks and delivered by lake vessel to the Milwaukee harbor with Valley and Milwaukee County power plants being the final destinations. Montana and Wyoming coal for Presque Isle Power Plant is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery. Colorado coal bound for the Presque Isle Power Plant is shipped via rail to Lake Superior and Lake Michigan (Chicago) coal transfer docks, respectively, for lake vessel delivery to the plant.
Certain of our coal transportation contracts contain fuel cost adjustments that are tied to the cost of fuel oil utilized by the locomotives. The PSCW has approved a program that allows us to hedge up to 75% of our potential fuel for electric generation in order to help manage our risk of higher delivered cost of coal. The costs of this program are included in our fuel and purchased power costs.
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.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of five operating plants with a dependable capability of approximately 1,971 MW at December 31, 2008. We added PWGS 1 and PWGS 2, both natural gas-fired units with a dependable capability of 545 MW each, in July 2005 and May 2008, respectively.
We purchase natural gas for these plants on the spot market from gas marketers, utilities and producers and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, balancing and storage agreements intended to support the plants' variable usage.
The PSCW has approved a program that allows us to hedge up to 75% of our estimated gas usage for electric generation in order to help manage our natural gas price risk. The costs of this program are included in our fuel and purchased power costs.
Oil-Fired Generation
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 is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at the Presque Isle Power Plant, diesel engines at the Pleasant Prairie Power Plant, Valley Power Plant and at the Manistique facility at Edison Sault. Our oil-fired generation had a dependable capability of approximately 262 MW as of December 31, 2008. Fuel oil requirements are purchased under agreements with suppliers.
Renewable Generation
Hydroelectric: Wisconsin Electric's hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 57 MW as of December 31, 2008. Of these 13 plants, 12 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.
Edison Sault's primary source of generation is its hydroelectric generating plant located on the St. Mary's River in Sault Ste. Marie, Michigan. The hydroelectric generating plant has a total dependable capability of approximately 27 MW. The water for this facility is under contract with the United States Army Corps of Engineers with tenure to December 31, 2075. However, the Secretary of the Army has the right to terminate the contract after December 31, 2050 by providing at least a five-year termination notice. No such notice can be given prior to December 31, 2045. Edison Sault pays for all water taken from the St. Mary's River at predetermined rates with a minimum annual payment of $0.1 million. The total flow of water taken out of Lake Superior, which in effect is the flow of water in the St. Mary's River, is under the direction and control of the International Joint Commission, created by the Boundary Water Treaty of 1909 between the United States and Great Britain, now represented by Canada.
Hydroelectric generation is also purchased by Edison Sault under contract from the United States Army Corps of Engineers' hydroelectric generating plant located within the Soo Locks complex on the St. Mary's River in Sault Ste. Marie, Michigan. This 17 MW contract has tenure to November 1, 2040 and cannot be terminated by the United States government prior to November 1, 2030.
Wind:
Wisconsin Electric completed the Blue Sky Green Field wind project in May 2008. This project has 88 turbines, an installed capacity of approximately 145 MW and a current dependable capability of approximately 29 MW. In July 2008, Wisconsin Electric purchased the development rights to a new wind farm site in central Wisconsin, Glacier Hills Wind Park, and we began the permitting process. In October 2008, we filed a request for a CPCN with the PSCW for the Glacier Hills Wind Park. We currently expect to install wind turbines with approximately 132 to 207 MW of generating capacity, subject to final site configuration and the turbine equipment selected. We expect 2012 to be the first full year of operation, subject to regulatory approvals and turbine availability. Additional information on wind generation is provided in Factors Affecting Results, Liquidity and Capital Resources -- Other Utility Rates and Regulatory Matters -- Wind Generation in Item 7.
Nuclear Generation
Point Beach: Prior to September 28, 2007, Wisconsin Electric owned two 518 MW electric generating units at Point Beach in Two Rivers, Wisconsin. On September 28, 2007, Wisconsin Electric 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 and 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, Wisconsin Electric is 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.
Nuclear Management Company: Prior to the Point Beach sale, we 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 our relationship with NMC was terminated.
Used Nuclear Fuel Storage & Disposal: For information concerning used nuclear fuel storage and disposal issues, see Nuclear Operations under Factors Affecting Results, Liquidity and Capital Resources in Item 7.
For further information on the sale of Point Beach, see Note D -- Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements in Item 8.
Power Purchase Commitments
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, 2008 with unaffiliated parties for the next five years:
Approximately 1,030 MW per year relates to the Point Beach long-term power purchase agreement. Under this agreement, we pay a predetermined price per MWh for energy delivered according to a schedule included in the agreement. The balance of these power purchase commitments are tolling arrangements whereby we are responsible for the procurement, delivery and the cost of natural gas fuel related to specific units identified in the contracts.
Electric Transmission and Energy Markets
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 Wisconsin Electric and Edison Sault, 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 Wisconsin Electric and Edison Sault are non-transmission owning members and customers of MISO.
We owned approximately 26.2% and 26.9% of ATC as of December 31, 2008 and 2007, 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, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and a new ancillary services market. For further information on MISO and the MISO Energy Markets, see Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition - Electric Transmission and Energy Markets in Item 7.
Electric Hedging Programs: 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 natural gas used for electric generation. We have PSCW approval to hedge up to 75% of the estimated monthly gas consumption for our owned and contracted gas-fired power plants. We integrate our natural gas hedging with the electric hedge program to ensure we do not over-hedge.
Finally, we seek to mitigate the risk of price increases in coal transportation costs for coal used in our coal-fired generating facilities. The coal transportation prices in some of our coal transportation contracts are tied to changes in a diesel fuel price index. Currently, financial diesel contracts are not actively traded; therefore, we are using financial heating oil contracts to mitigate this risk.
Electric Utility Operating Statistics
The following table shows certain electric utility operating statistics from 2004 to 2008 for electric operating revenues, MWh sales and customer data:
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
GAS UTILITY OPERATIONS
Our gas utility operations consist of Wisconsin Gas and the gas operations of Wisconsin Electric. Both companies 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. The two companies also transport customer-owned gas. Wisconsin Gas, the largest natural gas distribution utility in Wisconsin, operates throughout the state, including the City of Milwaukee. Wisconsin Electric's gas utility operates in three distinct
service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin.
Gas Deliveries
Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers. Annual gas sales are also impacted by the variability of winter temperatures.
Total gas therms delivered, including customer-owned transported gas, were approximately 2,273.8 million therms during 2008, a 3.5% increase compared with 2007. At December 31, 2008, we were transporting gas for approximately 1,400 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 39.8% of the total volumes delivered during 2008 and 42.0% during each of 2007 and 2006. We had approximately 1,056,400 and 1,049,500 gas customers at December 31, 2008 and 2007, respectively. Our peak daily send-out during 2008 was 1,625,928 Dth on February 10, 2008.
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 Wisconsin Electric's 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, 2013 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 normal weather.
Competition
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 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 sale of the natural gas commodity and related services are expected to remain subject to competition from third parties. It remains uncertain if and when the current economic disincentives for small customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to our smaller firm customers.
Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers despite periods of severe cold.
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.
We have extended our commitment on Guardian's original pipeline through December 2022. We have committed to purchase additional capacity through October 2023 on a new Guardian pipeline extension that is scheduled to be completed during 2009. The PSCW approved the construction of pipeline laterals to connect our gas distribution system to this pipeline in May 2007. In December 2007, FERC issued a CPCN to Guardian authorizing this extension project. Prior to April 2006, we held a one-third interest in Guardian.
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. During 2008, we have continued our 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 Wisconsin Gas and Wisconsin Electric, must contract for capacity and supply sufficient to meet the firm peak-day demand of their 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 the Wisconsin Electric and Wisconsin Gas GCRMs pursuant to which the companies have an opportunity to share in the cost savings. During 2008, we continued our active participation in the capacity release market. See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information on the GCRMs.
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 both Wisconsin Electric and Wisconsin Gas to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through their respective purchase gas adjustment mechanisms. Hedge targets (volumes) are provided annually to the PSCW as part of each company's 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 the companies' GCRMs.
Gas Utility Operating Statistics
The following table shows certain gas utility operating statistics from 2004 to 2008 for gas operating revenues, therms delivered and customer data:
(
a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
OTHER UTILITY OPERATIONS
Steam Utility Operations: Wisconsin Electric's steam utility generates, distributes and sells steam supplied by its Valley and Milwaukee County Power Plants. Wisconsin Electric operates a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from Wisconsin Electric's Valley Power Plant, a coal-fired cogeneration facility. Wisconsin Electric also operates 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 2008, the steam utility had $40.3 million of operating revenues from the sale of 3,081 million pounds of steam compared with $35.1 million of operating revenues from the sale of 2,965 million pounds of steam
during 2007. As of December 31, 2008 and 2007, steam was used by approximately 465 and 470 customers, respectively, for processing, space heating, domestic hot water and humidification.
Water Utility Operations: As of December 31, 2008, the water utility served approximately 3,060 water customers in the suburban Milwaukee area compared with approximately 3,040 customers as of December 31, 2007. Wisconsin Gas also provides contract services to local municipalities and businesses within its service territory for water system repair and maintenance. During 2008, the water utility had $3.2 million of operating revenues compared with $2.7 million of operating revenues during 2007.
We have reached an agreement to sell the water utility to the City of Mequon, Wisconsin for approximately $14.5 million, our book value. The completion of this sale is contingent upon the assignment of certain agreements, the approval by the PSCW and the ability of the City of Mequon to obtain financing. If these conditions are satisfied, we expect the sale to be completed in 2009.
UTILITY RATE MATTERS
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7.
NON-UTILITY ENERGY SEGMENT
Our non-utility energy segment is involved primarily in the design and construction of new generating capacity under our PTF strategy.
During 2000, we performed a comprehensive review of our existing portfolio of businesses and began implementing a strategy of divesting many of our non-utility energy segment businesses. Since 2000, we have sold our interest in many of our non-utility energy assets with proceeds from these sales totaling approximately $631.8 million. As we continue to implement our PTF strategy, we expect to grow the non-utility energy segment within the State of Wisconsin through the construction of new generating units by We Power.
We Power
We Power, through wholly owned subsidiaries, has designed and is constructing approximately 2,320 MW of new generation in Wisconsin, which is the key component of our PTF strategy. This new generation consists of approximately 1,230 MW of new generating capacity from two coal units that are being constructed in Oak Creek, Wisconsin and 1,090 MW of generating capacity related to PWGS 1 and PWGS 2, which provide 545 MW of dependable capability each. PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. In November 2005, two unaffiliated entities purchased an ownership interest of approximately 17%, or 200 MW of the two coal units. Similar to the generating capacity at PWGS 1 and PWGS 2, We Power will own the remaining 1,030 MW of generating capacity currently being constructed and will lease this capacity to Wisconsin Electric. At December 31, 2008, we had approximately $1,636.8 million of CWIP for the coal units currently under construction. For further information about our PTF strategy, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7.
Wisvest LLC
Wisvest was originally formed to develop, own and operate electric generating facilities and to invest in other energy-related entities. As a result of the change in corporate strategy to focus on our PTF strategy, Wisvest has discontinued its development activity. For the year ended December 31, 2008, Wisvest had $10.9 million of operating revenues from continuing operations compared with $11.9 million of operating revenues from continuing operations during 2007. We have divested substantially all of Wisvest's assets. As of December 31, 2008, Wisvest's sole operating asset and investment is Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center.
OTHER NON-UTILITY OPERATIONS
Wispark LLC
Wispark develops and invests in real estate, and as of December 31, 2008, has $32.4 million in real estate holdings. Wispark has developed several business parks primarily in southeastern Wisconsin. Wispark's flagship development, the 1,600-acre LakeView Corporate Park, which is owned through a joint venture, is located near Kenosha, Wisconsin. LakeView Corporate Park is home to approximately 80 companies located in almost 10 million square feet of buildings that have been developed on property in excess of 965 acres.
Wisconsin Energy Capital Corporation
This entity engages in investing and financing activities. Activities include advances to affiliated companies and investments in partnerships that develop low and moderate-income housing projects.
Minergy LLC
Minergy engages in the development and marketing of proprietary technologies designed to convert high volume industrial and municipal wastes into renewable energy and value-added products. In December 2008, management decided to close Minergy's operations. Minergy's only business is the operation of a GlassPack® facility in Zion, Illinois for the North Shore Sanitary District. Minergy's involvement in this facility is expected to end on March 31, 2009.
REGULATION
Wisconsin Energy Corporation
The Energy Policy Act, enacted in August 2005, repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to FERC. Wisconsin Energy was required to notify FERC of its status as a holding company and to seek from FERC the exempt status similar to that held by it under PUHCA 1935. In June 2006, Wisconsin Energy received notice from FERC confirming its status as a holding company and granting exempt status similar to that held under PUHCA 1935.
Non-Utility Asset Cap: Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants being constructed by We Power as part of our PTF strategy and assets used for providing environmental engineering services and for processing waste materials, from being counted against the asset cap provided that they are employed in qualifying businesses. As a result of these exemptions, our non-utility assets are significantly below the non-utility asset cap as of December 31, 2008.
Utility Energy Segment
Due to the Energy Policy Act's enactment of PUHCA 2005 as noted above, Wisconsin Electric was also required to notify FERC of its status as a holding company by reason of its ownership interest in ATC and to seek from FERC the exempt status similar to that held by it under PUHCA 1935. In June 2006, Wisconsin Electric received notice from FERC confirming its status as a holding company and granting exempt status similar to that held by it under PUHCA 1935.
Wisconsin Electric and Edison Sault 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 Wisconsin Electric and Edison Sault. Additionally, the Energy Policy Act created an Electric Reliability Organization to be
overseen by FERC, which established mandatory electric reliability standards, replacing the voluntary standards developed by the North American Electric Reliability Corporation, and which has the authority to levy monetary sanctions for failure to comply with the new standards.
Wisconsin Electric and Wisconsin Gas are subject to the regulation of the PSCW as to retail electric, gas, steam and water 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. Wisconsin Electric is subject to regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric and Edison Sault are both 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 the issuance of securities under most circumstances, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates. Wisconsin Electric's hydroelectric facilities are regulated by FERC. Wisconsin Electric and Edison Sault are subject to regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting. Edison Sault is subject to regulation of FERC with respect to the issuance of certain securities. For information on how rates are set for our regulated entities, see Utility Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.
The following table compares the source of our utility energy segment operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2008:
Total flow of water to Edison Sault's hydroelectric generating plant is under the control of the International Joint Commission, created by the Boundary Water Treaty of 1909 between the United States and Great Britain, now represented by Canada. The operations of Wisconsin Electric, Wisconsin Gas and Edison Sault are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ and the Michigan Department of Natural Resources.
Public Benefits and Renewable Portfolio Standard
In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Wisconsin Electric's baseline renewable energy percentage is 2.27%. Act 141 provides that for the years 2006-2009, Wisconsin Electric may not decrease its renewable energy percentage, and for the years 2010-2014, it must increase its renewable energy percentage at least two percentage points to a level of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the DOA back to the PSCW and/or contracted third parties. In addition, Act 141 requires that 1.2% of utilities' annual operating revenues be used to fund these programs. In July 2008, the Governor of Wisconsin's Task Force on Global Warming, which was established in 2008, issued a final report that recommended that this amount be increased to approximately 4%. It is not known at this time if that recommendation will be implemented.
The Task Force's report also includes an increased renewable portfolio standard. Pursuant to the Task Force's recommendations, the renewable portfolio standard would increase to 10% by 2013, 20% by 2020 and 25% by 2025. The legislature is expected to review these recommendations during 2009.
Public Act 295 enacted in Michigan calls for the implementation of a renewable portfolio standard by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
For additional information on Act 141 and current renewable projects see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters - Renewables, Efficiency and Conservation and Utility Rates and Regulatory Matters - Wind Generation in Item 7.
Non-Utility Energy Segment
We Power was formed to design, construct, own and lease the new generating capacity in our PTF strategy. We Power owns the interests in the companies constructing this new generating capacity (collectively, the We Power project companies). When complete, these facilities will be leased on a long-term basis to Wisconsin Electric. We Power has received determinations from FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies will not be deemed public utilities under the Federal Power Act and thus will not be subject to FERC's jurisdiction.
The Energy Policy Act and corresponding rules developed by FERC required us to seek FERC authorization to allow Wisconsin Electric to lease from We Power OC 1, OC 2 and PWGS 2. We received this authorization from FERC in December 2006. We were not required to request similar approval for the PWGS 1 lease between We Power and Wisconsin Electric as this unit was in service prior to the enactment of the Energy Policy Act.
In addition, for a short period prior to the transfer of each generation unit to Wisconsin Electric, We Power will be engaged in the sale of test power, a FERC jurisdictional transaction. We Power received approval from FERC for the sale of test power to Wisconsin Electric from PWGS 1 and PWGS 2, and for the transfer of any FERC jurisdictional facilities at Port Washington to Wisconsin Electric and/or ATC. We Power expects to submit its application seeking approval from FERC to sell test power from OC 1 in the first half of 2009. Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.
ENVIRONMENTAL COMPLIANCE
Environmental Expenditures
Expenditures for environmental compliance and remediation issues are included in anticipated capital expenditures described in Liquidity and Capital Resources in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.
Utility Energy Segment: Compliance with federal, state and local environmental protection requirements resulted in capital expenditures by Wisconsin Electric of approximately $135 million in 2008 compared with $31 million in 2007. Expenditures incurred during 2008 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric's power plants. These expenditures are expected to approximate $200 million during 2009, reflecting NOx, SO2 and other pollution control equipment needed to comply with various rules promulgated by the EPA.
Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $67.2 million during 2008 and $54.0 million during 2007.
Solid Waste Landfills
We provide for the disposal of non-ash related solid wastes and hazardous wastes through licensed independent contractors, but federal statutory provisions impose joint and several liability on the generators of waste for certain cleanup costs. Currently there are no active cases.
Coal-Ash Landfills
We currently have a successful program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and synthetic gypsum, which avoids the need for disposal in specially-designed landfills. Some early designed and constructed coal-ash landfills, which we used prior to developing this program, 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 made to define the nature and extent of any release, and work has been performed to address these conditions. For additional information, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8. Sites currently undergoing remediation and/or monitoring include the following:
Oak Creek North Landfill: Groundwater impairments at this landfill, located in the City of Oak Creek, Wisconsin, prompted Wisconsin Electric 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 being used as laydown area and parking. When construction activities are completed, a permanent cap will be installed.
Manufactured Gas Plant Sites
We are reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. See Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.
Air Quality
See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 for additional information concerning Air Quality.
Clean Water Act
See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 for additional information concerning the CWA.
Greenhouse Gas Emissions
See the caption, "We may face significant costs to comply with the regulation of greenhouse gas emissions." under Item 1A
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
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.
As of December 31, 2008, we owned the following generating stations:
(a)
Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility. The values were established by test and may change slightly from year to year.
(b)
We have a 25% interest in Edgewater 5 Generating Unit, which is operated by Alliant Energy Corp, an unaffiliated utility.
(c)
Effective July 2005, Wisconsin Electric began leasing PWGS 1, a natural gas-fired generation unit with 575 MW of dependable capability, from We Power under a 25 year lease.
(a)
Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility. The values were established by test and may change slightly from year to year.
(b)
We have a 25% interest in Edgewater 5 Generating Unit, which is operated by Alliant Energy Corp, an unaffiliated utility.
(c)
Effective July 2005 and May 2008, Wisconsin Electric began leasing PWGS 1 and PWGS 2, respectively, from We Power under 25 year leases. Both units are natural gas-fired generation units with 545 MW each of dependable capability.
(d)
The Byron Wind Turbines are able to generate up to 1.2 MW of electricity; however, due to the intermittent characteristics of wind power, their dependable capability is less than 1 MW.
(e)
Blue Sky Green Field is able to generate up to approximately 145 MW of electricity; however, due to the intermittent characteristics of wind power, its dependable capability is approximately 29 MW.
As of December 31, 2008, we operated approximately 23,210 pole-miles of overhead distribution lines and 22,210 miles of underground distribution cable, as well as approximately 378 distribution substations and 283,970 line transformers.
As of December 31, 2008, our gas distribution system included approximately 20,155 miles of distribution and transmission mains connected at 182 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian, Natural Gas Pipeline Company of America, Northern Natural Pipeline Company, Great Lakes
Transmission Company, Viking Gas Transmission and Michigan Consolidated Gas Company. We have liquefied natural gas storage plants which convert and store, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plants have a send-out capability of 73,600 Dth per day. We also have propane air systems for peaking purposes. These propane air systems will provide approximately 2,400 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 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, 2008, 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, nine miles of walkable tunnels and other pressure regulating equipment.
We Power: We Power completed construction of PWGS 1 and PWGS 2, both natural gas units with a dependable capability of 545 MW each, in July 2005 and May 2008, respectively. We Power also received authorization from the PSCW to build two 615 MW coal plants (of which we will own approximately a 515 MW share of each unit) adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. Construction commenced at this site in June 2005. For information about PTF, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7.
Wisvest LLC: Wisvest owns a chilled water production and distribution facility located in Milwaukee County, Wisconsin.
Wispark LLC: As of December 31, 2008, Wispark owned in full or through minority interests in joint ventures, the following commercial and industrial parks in the state of Wisconsin: LakeView Corporate Park located near Kenosha, Wisconsin and GrandView Business Park in Racine, Wisconsin. Wispark developed Gaslight Pointe, a residential and commercial complex located in Racine. Wispark owns other properties located in Wisconsin Electric's service territories that are held for future development or sale. Wispark is a minority owner in an industrial park located in Gurnee, Illinois.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
In addition to those legal proceedings discussed below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.
ENVIRONMENTAL MATTERS
We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. Management believes that, perhaps with immaterial exceptions, our existing facilities are in compliance with applicable environmental requirements.
EPA Information Requests: Wisconsin Electric and Wisconsin Gas responded to an EPA request received in August 2004, 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 Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site, Milwaukee Solvay Coke Company. In July 2005, Wisconsin Gas received a general notice letter from the EPA identifying Wisconsin Gas as
a potentially responsible party under CERCLA. In April 2006, we received a special notice letter from the EPA identifying both Wisconsin Gas and Wisconsin Electric as potentially responsible parties and commencing a negotiation period with the EPA and other parties regarding the conduct of a RI/FS and reimbursement of the EPA's costs. Wisconsin Electric and Wisconsin Gas, 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 investigation activities began in late 2008. Under the Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities at this time. The companies' 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 S -- 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 - Consent Decree in Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal-ash landfills, manufactured gas plant sites and air quality.
UTILITY RATE MATTERS
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters and Power the Future in Item 7 for information concerning rate matters in the jurisdictions where Wisconsin Electric, Wisconsin Gas and Edison Sault do business.
OTHER MATTERS
Used Nuclear Fuel Storage and Removal: See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 for information concerning the DOE's breach of contract with Wisconsin Electric that required the DOE to begin permanently removing used nuclear fuel from Point Beach by January 31, 1998.
Stray Voltage:
In recent years, several actions by dairy farmers have been commenced or claims made against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of its electrical system. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7.
For information regarding additional legal matters, see Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7. For information concerning our PTF strategy, including the dispute with Bechtel, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the fourth quarter of 2008.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 2008 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.
Gale E. Klappa. Age 58.
Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President since April 2003.
Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Director of Joy Global, Inc.
Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.
Charles R. Cole. Age 62.
Wisconsin Electric -- Senior Vice President since 2001.
Wisconsin Gas -- Senior Vice President since July 2004.
Stephen P. Dickson. Age 48.
Wisconsin Energy -- Vice President since 2005. Controller since 2000.
Wisconsin Electric -- Vice President since 2005. Controller since 2000.
Wisconsin Gas -- Vice President since 2005. Controller since 1998.
James C. Fleming. Age 63.
Wisconsin Energy -- General Counsel since March 2006. Executive Vice President since January 2006.
Wisconsin Electric -- General Counsel since March 2006. Executive Vice President since January 2006.
Wisconsin Gas -- General Counsel since March 2006. Executive Vice President since January 2006.
Southern Company Services, Inc. -- Vice President and Associate General Counsel from 1998 to December 2005. Southern Company Services is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
Frederick D. Kuester.
Age 58.
Wisconsin Energy -- Executive Vice President since May 2004.
Wisconsin Electric -- Executive Vice President since May 2004. Chief Operating Officer since October 2003.
Wisconsin Gas -- Executive Vice President since May 2004.
Allen L. Leverett. Age 42.
Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Wisconsin Electric -- Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Kristine A Rappé. Age 52.
Wisconsin Energy -- Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 2003 to April 2004.
Wisconsin Electric -- Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 1994 to April 2004.
Wisconsin Gas -- Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 2001 to April 2004.
Certain executive officers also hold offices in our non-utility subsidiaries.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NUMBER OF COMMON STOCKHOLDERS
As of December 31, 2008, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 48,400 registered stockholders.
COMMON STOCK LISTING AND TRADING
Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC." Daily trading prices and volume can be found in the "NYSE Composite" section of most major newspapers, usually abbreviated as WI Engy.
DIVIDENDS AND COMMON STOCK PRICES
Common Stock Dividends of Wisconsin Energy: Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, earnings, financial condition and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note J -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.
In December 2008, our Board of Directors approved a new common stock dividend policy. Pursuant to this new policy, we will target a dividend payout ratio between 40% and 45% of earnings for the years 2009 through 2011. We plan to target a dividend payout ratio of 45% to 50% of earnings after 2011. In accordance with the new policy, on January 29, 2009, our Board of Directors announced that it increased our common stock quarterly dividend rate by 25% to $0.3375 per share. With the increase, the new dividend is equivalent to an annual rate of $1.35 per share.
Range of Wisconsin Energy Common Stock Prices and Dividends:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
This table does not include shares purchased by independent agents to satisfy obligations under our employee benefit plans and stock purchase and dividend reinvestment plan. All shares reported during the quarter were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.
ITEM 6
ITEM 6
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
INTRODUCTION
Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment and a non-utility energy segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.
Our utility energy segment, consisting of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies", and Edison Sault, is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Our non-utility energy segment primarily consists of We Power. We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long-term lease to Wisconsin Electric under our PTF strategy.
CORPORATE STRATEGY
Business Opportunities
We seek to increase stockholder value by leveraging on our core competencies. Our key corporate strategy, announced in September 2000, is PTF. This strategy is designed to address Wisconsin's growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel-diverse, reasonably priced electric supply. It is also designed to improve the delivery of energy within our distribution systems to meet increasing customer demands and to support our commitment to improved environmental performance. Our PTF strategy, which is discussed further below, is having and is expected to continue to have, a significant impact on our utility and non-utility energy segments. In July 2005, the first of four new electric generating units under our PTF strategy was placed into service. The second unit was placed in service in May 2008. Construction on the remaining two units is underway with OC 1 scheduled to be placed in service by the end of 2009 and OC 2 scheduled to be placed in service in the fall of 2010.
Utility Energy Segment: Our utility energy segment strives to provide reasonably priced energy delivered at high levels of customer service and reliability. We expect our prices to continue to be established by our regulatory bodies under traditional rate based, cost of service methodologies. We continue to gain efficiencies and improve the effectiveness of our service deliveries through the combined support operations of our electric and gas businesses. We work to obtain a reliable, reasonably-priced supply of electricity through plants that we operate and various long-term supply contracts.
Non-Utility Energy Segment: Our primary focus in this segment is to improve the supply of electric generation in Wisconsin. We Power was formed to design, construct, own and lease new generation assets under our PTF strategy.
Power the Future Strategy: In February 2001, we filed a petition with the PSCW that would allow us to begin implementing our 10-year PTF strategy to improve the supply and reliability of electricity in Wisconsin. PTF is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. Under PTF, we are (1) investing approximately $2.6 billion in 2,120 MW of new natural gas-fired and coal-fired generating capacity at existing sites; (2) upgrading our existing electric generating facilities; and (3) investing in upgrades of our existing energy distribution system.
In November 2001, we created We Power to design, construct, own and lease the new generating capacity. Wisconsin Electric will lease each new generating facility from We Power as well as operate and maintain the new plants under 25- to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, we expect to recover the investments in We Power's new facilities over the initial lease term. At the end of the leases, Wisconsin Electric will have the right to acquire the plants outright at market value or to renew the leases.
Wisconsin Electric expects that payments under the plant leases will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.
Under our PTF strategy, we expect a significant portion of our future generation needs will be met through We Power's construction of the PWGS units and the Oak Creek expansion.
As of December 31, 2008:
We completed the construction of our two 545 MW natural gas-fired intermediate load units in Port Washington, Wisconsin (PWGS 1 and PWGS 2). PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. Both units are fully operational and were completed within the PSCW approved cost parameters.
We have made significant progress on construction of the two 615 MW coal-fired base load units (OC 1 and OC 2) adjacent to the site of our existing Oak Creek Power Plant in Oak Creek, Wisconsin (the Oak Creek expansion), with OC 1 scheduled to be in service in late 2009 and OC 2 in fall 2010. All environmental permits have been received. The WDNR issued a final modified WPDES Permit in July 2008.
We completed the planned sale of approximately a 17% (200 MW) ownership interest in the Oak Creek expansion to two co-owners.
Through December 31, 2008, we have financed our PTF expenditures with internally generated cash, asset sales and debt financings. Future expenditures are expected to be financed with internally generated cash and debt financings. We currently do not plan to issue any new common equity as part of our PTF strategy.
Our primary risks under PTF are construction risks associated with the schedule and costs for our Oak Creek expansion; changes in applicable laws or regulations; adverse interpretation or enforcement of permit conditions, laws or regulations by the permitting agencies; the ability to obtain necessary operating permits in a timely manner; obtaining the investment capital from outside sources necessary to implement the strategy; governmental actions; and events in the global economy.
For further information concerning PTF capital requirements, see Liquidity and Capital Resources below. For additional information regarding risks associated with our PTF strategy, including a discussion of the claims submitted by Bechtel, the contractor for the Oak Creek expansion, and the regulatory process and specific regulatory approvals, see Factors Affecting Results, Liquidity and Capital Resources below.
Sale of Point Beach: In September 2007, Wisconsin Electric 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 and associated inventories and assumed the obligation to decommission the plant. Wisconsin Electric retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, Wisconsin Electric deferred the net gain on the sale of approximately $418 million as a regulatory liability and deposited those proceeds into a restricted cash account.
In connection with the sale, Wisconsin Electric also transferred $390 million of decommissioning funds to the buyer. Wisconsin Electric then liquidated the balance of the decommissioning trust assets and retained approximately $552 million, which was also placed into the restricted cash account. We are using the cash in the restricted cash account and the interest earned on the balance for the benefit of our customers and to pay certain taxes related to the liquidation of the qualified decommissioning trust. Our regulators are directing the manner in which these proceeds will benefit customers. For further information on the 2008 rate case, see Utility Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in this report.
A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, Wisconsin Electric is 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 are paying a pre-determined 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 this report.
Divestiture of Assets
Our PTF strategy led to a decision to divest non-core businesses. These non-core businesses primarily included non-utility generation assets located outside of Wisconsin and a substantial amount of Wispark's real estate portfolio, as well as our manufacturing business. In addition, in 2001 we contributed our transmission assets to ATC and received cash proceeds of $119.8 million and an economic interest in ATC. Finally, in 2006 we concluded that it was in the best interests of customers and stockholders to sell Point Beach. In 2007, we sold Point Beach for approximately $924 million. Since 2000, we have received total proceeds of approximately $3.1 billion from the divestiture of assets.
RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
The following table compares our operating income by business segment and our net income for 2008, 2007 and 2006:
An analysis of contributions to operating income by segment and a more detailed analysis of results in 2008, 2007 and 2006 follow.
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
2008 vs. 2007: Our utility energy segment contributed $581.9 million of operating income during 2008 compared with $586.0 million of operating income during 2007. During 2008, we experienced less favorable weather in the summer months, which decreased electric sales. In addition, our fuel and purchased power costs increased primarily as a result of the power purchase agreement entered into upon the sale of Point Beach. Finally, our other operating and maintenance expenses were higher due primarily to increased regulatory amortizations allowed in rates. These items were largely offset by our rate increases and increased margin from gas sales due to colder weather.
2007 vs. 2006: Our utility energy segment contributed $586.0 million of operating income during 2007 compared with $532.8 million of operating income during 2006. During 2007, we experienced more favorable weather which increased electric and gas sales. In addition, we experienced an increase in retail sales as a result of customer growth and we reached a settlement regarding a billing dispute with our largest customers, two iron ore mines. These items were partially offset by an increase in fuel and purchased power expenses.
The following table summarizes our utility energy segment's operating income during 2008, 2007 and 2006:
(a)
In September 2007, we sold Point Beach and commenced purchasing power from the new owner under a power purchase agreement. As a result of the sale and the power purchase agreement, our 2008 earnings reflect higher fuel and purchased power costs as compared to 2007. In addition, our 2008 operating income reflects lower other operation and maintenance costs and lower depreciation, decommissioning and amortization costs as we no longer own Point Beach.
In January 2008, Wisconsin Electric received a rate order from the PSCW that authorized a 17.2% increase in electric rates to recover increased costs associated with transmission expenses, our PTF program, environmental expenditures, continued investment in renewable and efficiency programs and recovery of previously deferred regulatory assets. The PSCW allowed us to issue bill credits to our customers from the proceeds of the net gain and excess decommissioning funds associated with the sale of Point Beach to mitigate this increase. As a result of these bill credits, we estimate that the January 2008 PSCW rate order resulted in a net 3.2% increase in electric rates paid by our Wisconsin customers in 2008 and will result in another net increase of 3.2% in 2009. The bill credits that we issue to our customers and the proceeds immediately applied to regulatory assets are reflected on our income statement in the amortization of the gain on the sale of Point Beach. As we issue the bill credits, we transfer the cash from a restricted account to an unrestricted account. The transferred cash is equal to the bill credits, less taxes.	
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 2008 with similar information for 2007 and 2006, including a summary of electric operating revenues and electric sales by customer class:
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.
Electric Utility Revenues and Sales
2008 vs. 2007: Our electric utility operating revenues decreased by $19.3 million, or 0.7%, when compared to 2007. The largest factor in this decline was a one-time $62.5 million FERC approved refund to our wholesale customers associated with their share of the gain on the sale of Point Beach. Consistent with past practices, the refund was recorded as a reduction in wholesale revenues. Because the refund came from the restricted cash associated with the sale of Point Beach, a corresponding entry was made to amortize the gain on the sale of Point Beach.
We also estimate that weather reduced our revenues by approximately $28.3 million for the year ended December 31, 2008 as compared the same period in 2007. As measured by cooling degree days, 2008 was approximately 25.9% cooler than 2007 and 17.5% cooler than normal. Opportunity sales declined by approximately $44.1 million primarily because of less favorable weather, which reduced demand for our higher cost generation that was not being utilized to serve our retail customers. In addition, we experienced a $9.0 million decrease in revenue related to the settlement of a billing dispute with our largest customers, two iron ore mines, that occurred in 2007. Partially offsetting these decreases, we estimate that our electric revenues were approximately $142.9 million higher than the same period in 2007 because of pricing increases we received in the January 2008 PSCW rate case, the interim April 2008 and final July 2008 PSCW fuel orders and a wholesale rate increase effective in May 2007. For more information on the pricing increases and the fuel cost adjustment clause, see Utility Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources.
We estimate that sales to large commercial and industrial customers will decline in 2009 because of the current economic conditions. However, we expect our total electric utility operating revenues to increase in 2009 primarily due to the scheduled reduction of Point Beach bill credits, the full year impact of the 2008 rate increase and the impact of the one-time refund to FERC wholesale customers in 2008.
2007 vs. 2006: Our electric utility operating revenues increased by $176.3 million, or 7.0%, when compared to 2006. The biggest drivers of the increase in revenues related to the recognition of revenues attributable to fuel and purchased power of approximately $37.4 million and increased revenues related to Resale - Utilities of approximately $30.4 million. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $37.4 million of reserves to reflect amounts that were refunded to customers. No such reserves were established in 2007 as we experienced higher fuel and purchased power costs. The increase in Resale - Utilities reflects our ability to sell electricity into the MISO and PJM markets due to the increased availability of our baseload plants.
In addition, we estimate that $27.1 million of the increase in operating revenues related to pricing increases. This increase primarily reflects rate increases received in late January 2006 that were in effect for the entire twelve months ended December 31, 2007 and a wholesale rate increase effective May 2007. We also estimate that $28.9 million of the increase was due to more favorable weather and $22.8 million relates to sales growth in residential and commercial sales. Finally, approximately $9.0 million of the increase relates to the settlement in the second quarter of 2007 of a billing dispute with our largest customers, two iron ore mines.
Our retail electric sales volume grew by approximately 2.2%. The increase in retail sales was driven by growth in residential and commercial sales and more favorable weather in 2007 as compared to the same period in 2006. In 2007, heating degree days increased by approximately 7.7% compared to 2006, and cooling degree days increased by approximately 10.7%.
Electric Fuel and Purchased Power Expenses
2008 vs. 2007: Our fuel and purchased power costs increased by $241.6 million, or approximately 24.4%, when compared to 2007. The largest factor related to this increase was the power purchase agreement we entered into in connection with the sale of Point Beach, which increased costs by approximately $247.0 million. In addition, in connection with the January 2008 PSCW rate order, we recorded a $41.2 million one-time amortization of deferred fuel costs in the first quarter of 2008. After adjusting for the Point Beach power purchase agreement and one-time amortization of deferred fuel cost, fuel and purchased power costs decreased by approximately $46.6 million, or 4.7%. Cost increases resulting from higher natural gas prices, purchased energy and coal and related transportation prices were more than offset by lower costs resulting from reduced MWh sales during 2008 as compared to 2007.
We expect that electric fuel and purchased power expenses in 2009 will be impacted by the price of natural gas, the increased cost of coal and related transportation prices and changes in electric sales.
2007 vs. 2006: Our fuel and purchased power expenses increased by $192.1 million, or approximately 24.1%, when compared to 2006. Our total electric sales volume increased by approximately 3.6%, when compared to 2006. However, our average fuel and purchased power costs increased by $4.86 per MWh, or approximately 20.6%. The largest factors for the higher cost per MWh are the power purchase agreement entered into in connection with the sale of Point Beach, which increased costs by approximately $47.0 million, increased coal and transportation costs, increased market prices for purchased energy and an increase in production of gas-fired generation used for opportunity sales.
Gas Utility Revenues, Gross Margin and Therm Deliveries
The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2008, 2007 and 2006:
We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under GCRMs. The following table compares our gas utility gross margin and therm deliveries by customer class during 2008, 2007 and 2006:
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.
2008 vs. 2007:
Our gas margins increased by $44.8 million, or approximately 10.5%, when compared to 2007. We estimate that approximately $22.5 million of this increase related to pricing increases that we received in the January 2008 PSCW rate order. Additionally, we estimate that weather had a positive impact on our gas margin of approximately $13.9 million. Temperatures (as measured by heating degree days) were 8.7% colder in 2008 as compared to 2007, and 5.9% colder than normal.
We expect our gas margins in 2009 will be impacted by weather; however, as noted above, 2008 was colder than normal.
2007 vs. 2006:
Our gas margins increased by $26.9 million, or 6.7%, between the comparative periods. We estimate that approximately $21.7 million of this increase related to increased sales as a result of more normal winter weather. Temperatures (as measured by heating degree days) were approximately 7.7% colder in 2007 as compared to 2006. As a result, our retail therm deliveries increased approximately 7.7% from 2006. In addition, we estimate that our gas margins improved by $6.6 million due to a rate order that went into effect in the latter part of January 2006 and was effective for the entire twelve months ended December 31, 2007.
Other Operation and Maintenance Expense
2008 vs. 2007: Our other operation and maintenance expenses increased by approximately $278.6 million, or 23.7%, when compared to 2007. The January 2008 PSCW rate order allowed for pricing increases related to transmission costs, PTF lease costs and the amortization of other deferred costs. These items were $262.8 million higher in 2008 as compared to 2007. In addition to these regulatory amortizations, in connection with the January 2008 PSCW rate order, we recorded a one-time $43.8 million amortization of deferred bad debt costs in the first quarter of 2008. We also incurred approximately $64.1 million of increased expenses related to the operation and maintenance of our power plants and electric distribution system. These increased costs were also considered in the rate setting process. These increases were partially offset by a $119.7 million decrease in nuclear operation and maintenance expense related to Point Beach as we no longer own the plant.
Our utility operation and maintenance expenses are influenced by wage inflation, employee benefit costs, plant outages and the amortization of regulatory assets. We expect our 2009 other operation and maintenance expense to decrease due to the impact of the $43.8 million one-time amortization of deferred bad debt costs in 2008 and other overall cost reduction efforts implemented in response to the current economic recession.
2007 vs. 2006: Our other operation and maintenance expense decreased by $36.9 million, or 3.0%, when compared to 2006. This decrease was primarily because of a decline in nuclear operations expense of approximately $37.8 million because we owned Point Beach for only nine months in 2007 as compared to a full year in 2006. Additionally, fossil operations expense decreased by approximately $6.0 million due to fewer planned outages in 2007 as compared to 2006. These decreases were partially offset by an increase of $12.7 million in regulatory amortizations as a result of the January 2006 rate order. The January 2006 rate order covered increased expenses related to transmission costs, bad debt costs and PTF costs.
Depreciation, Decommissioning and Amortization Expense
2008 vs. 2007: Depreciation, decommissioning and amortization expense decreased by approximately $11.1 million, or 3.5%, when compared to 2007. The 2007 sale of Point Beach reduced depreciation, decommissioning and amortization expense by approximately $24 million as we no longer own the plant. Partially offsetting this decline was higher depreciation related to new projects including the Blue Sky Green Field wind project that was placed in service in May 2008.
We expect depreciation, decommissioning and amortization expense to increase in 2009 as a result of an overall increase in utility plant in service.
2007 vs. 2006: Depreciation, decommissioning and amortization expense increased by $1.2 million, or 0.4%, when compared to 2006. This increase was the result of increased depreciation for normal plant additions and coal- related environmental controls that were placed in service in November 2006. These increases were partially offset by a reduction in depreciation and decommissioning costs as a result of the sale of Point Beach in September 2007.
Amortization of Gain
In connection with the September 2007 sale of Point Beach, we reached agreement with our regulators to allow for the net gain on the sale of approximately $902.2 million to be used for the benefit of our customers. The majority of the benefits are being returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it is being amortized to the income statement as we issue bill credits or make refunds to customers. When the bill credits and refunds are issued to customers, we transfer cash from the restricted accounts to the unrestricted accounts, adjusted for taxes.
During 2008 and 2007, the Amortization of Gain was as follows:
In 2009, we expect to see a reduction in the Amortization of Gain because of the one-time entries identified above, as well as an expected approximately $100 million decrease in bill credits to retail customers compared to 2008.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
The most significant subsidiary included in this segment is We Power, which constructs and owns power plants associated with our PTF strategy and leases them to Wisconsin Electric. This segment primarily reflects revenues billed under the leases for PWGS 1, PWGS 2 and the Oak Creek coal handling system, and the related depreciation expense.
The following table compares our non-utility energy segment's operating income during 2008, 2007 and 2006:
Note: We Power's PTF lease revenues and Wisconsin Electric's lease costs are eliminated in consolidation.
2008 vs. 2007:
Our non-utility energy segment contributed $89.3 million of operating income in 2008 compared to operating income of $47.4 million in 2007. This increase was primarily related to lease income from PWGS 2, which was placed in service in May 2008, and the full year impact of the coal handling system for Oak Creek, which was placed in service in November 2007.
In 2009, we expect our non-utility energy segment to generate higher operating income as PWGS 2 will be in service for a full year. In addition, we will recognize lease income on the new water intake system for Oak Creek that was placed in service in January 2009, which supplies cooling water to the existing units at Oak Creek.
2007 vs. 2006: Our non-utility energy segment contributed $47.4 million of operating income in 2007 compared to operating income of $43.1 million in 2006. This increase was primarily related to the Oak Creek coal handling system that was placed in service during the fourth quarter of 2007.
CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME
2008 vs. 2007: Corporate and other affiliates had an operating loss of $10.6 million in 2008 compared with an operating loss of $4.9 million in 2007. The increase in operating loss was primarily related to reduced real estate sales during 2008 as compared to 2007. In the foreseeable future, we expect to have slight operating losses as we have minimal business operations in this segment.
2007 vs. 2006: Corporate and other affiliates had an operating loss of $4.9 million in 2007 compared with an operating loss of $7.4 million in 2006. The favorable change was primarily related to our Wispark operations, which had operating income during 2007 as compared to operating losses throughout 2006.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET
The following table identifies the components of consolidated other income and deductions, net during 2008, 2007 and 2006:
2008 vs. 2007: Other income and deductions, net decreased by $31.9 million when compared to 2007. In connection with the January 2008 PSCW rate order, we stopped accruing carrying charges on regulatory assets as we are now allowed a current return on them. Additionally, in 2007 we recognized approximately $13.1 million on property sales, most of which related to land sales in northern Wisconsin and the Upper Peninsula of Michigan, as compared to $2.6 million in 2008.
During 2009 we expect to see an increase in Other Income and Deductions, net as we expect AFUDC - Equity to increase for the Oak Creek AQCS project.
2007 vs. 2006: Other income and deductions, net decreased by $4.2 million when compared to 2006. The reduction primarily reflects a decrease in AFUDC of $9.4 million in connection with the environmental controls related to the new scrubber placed in service at our Pleasant Prairie Power Plant in the fourth quarter of 2006. This scrubber was installed as part of the implementation of our EPA consent decree. For further information on the consent decree with the EPA, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in this report. This reduction was offset, in part, by an increase in gains on sales of property primarily associated with land sold in northern Wisconsin and the Upper Peninsula of Michigan.
CONSOLIDATED INTEREST EXPENSE, NET
2008 vs. 2007: Interest expense, net decreased by $13.9 million in 2008 when compared with 2007. Our gross interest costs decreased by $0.6 million because of lower short-term interest rates that were offset in part by higher debt balances. Our capitalized interest increased $13.3 million, primarily because of increased construction in progress at our Oak Creek units.
During 2009, we expect gross interest expense to increase due to increased debt levels to fund our planned construction activity; however, these increases are expected to be mitigated by increases in our capitalized interest.
2007 vs. 2006: Interest expense, net decreased by $5.1 million in 2007 when compared with 2006. Our gross interest costs increased by $28.3 million because of higher debt levels primarily related to our PTF construction program. However, our capitalized interest increased by $33.4 million due to higher levels of construction in progress at our PTF plants, which resulted in a reduction of our net interest expense.
CONSOLIDATED INCOME TAXES
2008 vs. 2007: Our effective tax rate applicable to continuing operations was 37.7% in 2008 compared to 39.2% in 2007. This reduction in our effective tax rate was the result of increases in the production tax deductions and wind credits. These items were considered by the PSCW in setting our rates in the January 2008 PSCW rate order; therefore, the lower effective tax rate did not have a significant impact on net income. For further information see Note H -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2009 annual effective tax rate to range between 35% and 37%.
2007 vs. 2006: Our effective tax rate applicable to continuing operations was 39.2% in 2007 compared to 35.9% in 2006. In 2006, we reversed $5.8 million of valuation allowance associated with state net operating loss carry forwards as we concluded that it was more likely than not that we would realize these benefits. Excluding these items, our 2006 effective tax rate was 37.1%.
DISCONTINUED OPERATIONS
The following table identifies the primary components of net income (loss) from discontinued operations during 2008, 2007 and 2006:
Our 2008 and 2007 earnings from discontinued operations reflect resolution of tax liabilities. Our 2006 earnings from discontinued operations reflect a loss on the sale of Minergy Neenah LLC, the 2006 operations of the plant and income of approximately $2.4 million related to the favorable resolution of tax liabilities.
See Note D -- Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements for further information regarding the transactions described above.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2008, 2007 and 2006:
Operating Activities
2008 vs. 2007: Cash provided by operating activities was $737.0 million during 2008 which was $204.5 higher than 2007, primarily because of higher cash earnings and lower tax payments.
During 2008, our cash earnings were higher than in 2007 because of increased amortizations of deferred costs associated with regulatory assets. During 2008, our cash taxes were $289.2 million lower than 2007, primarily because of additional tax depreciation, increased deductions for contributions to our pension plan and deferred taxes associated with the nuclear decommissioning trust assets. In accordance with IRS guidelines, we completed a review in 2008 and concluded that certain timing items that historically had been capitalized and depreciated for tax purposes could be deducted currently. In January 2009, we contributed $270 million to our qualified pension plan which resulted in a tax deduction for 2008.
2007 vs. 2006: Cash provided by operating activities was $532.5 million during 2007, which is $197.5 million lower than 2006. This decline was due primarily to higher tax payments, lower fuel recoveries and changes in working capital. In 2007, we paid approximately $108 million in cash taxes because of the Point Beach sale and the liquidation of the nuclear decommissioning trust. In addition, cash taxes from operating income were higher due to higher taxable income. Our cash from fuel collections was unfavorable in 2007 as compared to 2006 because in 2006 we over-collected fuel and purchased power costs and in 2007 we under-collected such costs.
Investing Activities
2008 vs. 2007: Cash used in investing activities was $906.9 million during 2008, an increase of $363.7 million over 2007. This increase reflects a reduction in proceeds from asset sales, partially offset by lower capital expenditures and an increase in restricted cash from the sale of Point Beach released to us.
During 2008, we released $345.1 million of restricted cash. In September 2007, we sold Point Beach and received approximately $924 million and retained approximately $552 million of decommissioning funds. We placed approximately $924 million in restricted accounts to be used for the payment of taxes and for the benefit of our customers. We release the restricted cash, adjusted for taxes, as we issue bill credits to our customers, which is reflected as an amortization of the gain on our income statement. We expect to release approximately $214.1 million of restricted cash during 2009 as we issue fewer bill credits to our retail customers from the Point Beach proceeds pursuant to the terms of our 2008 rate order.
During 2008, our capital expenditures decreased $74.4 million primarily due to reduced construction spending related to our PTF generation plants. This was partially offset by increased spending at Wisconsin Electric related to the completion of our Blue Sky Green Field wind project and the start of construction of the Oak Creek AQCS project. During 2009, we expect our capital expenditures to be lower than 2008 because we are nearing the completion of construction of the PTF generation plants.
2007 vs. 2006: Cash used in investing activities was $543.2 million during 2007, a reduction of $396.3 million over 2006. The two most significant factors related to cash used in investing activities related to capital expenditures and the unrestricted proceeds we received from the sale of Point Beach. Our 2007 capital expenditures exceeded $1.2 billion, an increase of $282.8 million over 2006. This increase was expected and it primarily reflects the continued construction efforts with our PTF generation plants.
During 2007, we experienced a significant inflow of cash related to the sale of Point Beach; however, we restricted a significant amount of that cash as it will be used for the benefit of our customers. The 2007 cash flows related to the Point Beach sale are summarized as follows:
As the gain on the Point Beach sale is given back to customers, primarily in the form of bill credits, we release the restricted cash.
The following table identifies capital expenditures by year:
Financing Activities
The following table summarizes our cash flows from financing activities:
2008 vs. 2007: During 2008, cash provided by financing activities was $175.0 million compared to $1.1 million in 2007. During 2008, we issued a total of $966 million in long-term debt and retired $350.8 million of long-term debt. The net proceeds were used to repay short-term debt. For additional information on the debt issues, see Note K -- Long-Term Debt in the Notes to Consolidated Financial Statements.
Our common stock dividends increased in 2008 as we raised our dividend rate by 8%. In January 2009, our Board of Directors approved a 25% increase in the quarterly common stock dividend.
2007 vs. 2006: During 2007, cash provided by financing activities was $1.1 million compared to $173.3 million in 2006. This decline occurred because we did not issue as much net new debt in 2007 as compared to 2006. The decline in the amount of net new debt is directly related to the unrestricted cash we received from the sale of Point Beach as discussed above.
During 2007, we issued $500 million principal amount of Junior Notes and we used the net proceeds from these notes to pay down short-term debt incurred to fund our PTF construction and for other working capital purposes. In December 2007, Wisconsin Electric retired $250 million of 3.50% Notes due December 1, 2007.
No new shares of Wisconsin Energy's common stock were issued in 2008, 2007 or 2006. During these years, our plan agents purchased, in the open market, 0.5 million shares at a cost of $23.0 million, 1.4 million shares at a cost of $67.8 million and 1.1 million shares at a cost of $48.0 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2008, 2007 and 2006, we received proceeds of $11.6 million, $36.1 million and $26.8 million, respectively, related to the exercise of stock options. In addition, we instructed our independent agents to purchase shares of our common stock in the open market to satisfy our obligation under our dividend reinvestment plan and various employee benefit plans.
CAPITAL RESOURCES AND REQUIREMENTS
In 2000, we announced a growth strategy which, among other things, called for us to sell certain assets and reduce our debt levels. Our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 58.5% at December 31, 2008 due primarily to these asset sales. Over the next several years, we expect to have some limited asset sales, but at levels significantly lower than prior years. For more information, see Note D -- Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements in this report.
Capital Resources
We anticipate meeting our capital requirements during 2009 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2009, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings and the issuance of debt securities.
During the second half of 2008, the global credit markets suffered a significant contraction, including the failure of some large financial institutions. As a result, interest rates on our short-term and variable rate tax-exempt debt increased during the second half of 2008, but have since stabilized. Despite the turmoil in the credit markets, Wisconsin Electric was able to remarket its $147 million tax-exempt bonds in August 2008 and to issue in October 2008 $300 million of 6.00% Debentures due April 1, 2014 and in December 2008 $250 million of 6.25% Debentures due December 1, 2015. Also in December 2008, Wisconsin Energy borrowed $260 million under an eighteen-month credit agreement.
As indicated above, despite the recent turmoil in the global credit markets, we still currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets and internally generated cash. Our short-term interest rates have stabilized and currently are lower than they were during the second half of 2008.
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.
An affiliate of Lehman Brothers Holdings, which filed for bankruptcy in September 2008, provided approximately $80 million of commitments under our bank back-up credit facilities on a consolidated basis. We have no current plans to replace Lehman's commitments. Excluding Lehman's commitments, as of December 31, 2008, we had approximately $1.6 billion of available, undrawn lines under our bank back-up credit facilities. As of December 31, 2008, we had approximately $602.3 million of short-term debt outstanding on a consolidated basis that was supported by the available lines of credit.
We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities at December 31, 2008:
*
Excludes Lehman's commitments
Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.
In connection with the conversion of the interest rate determination method for certain Wisconsin Electric tax-exempt bonds in August 2008, Wisconsin Electric terminated its $100 million six-month bank back-up credit facility that was scheduled to expire in September 2008.
The following table shows our capitalization structure as of December 31, 2008 and 2007, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view the Junior Notes:
Included in Long-Term Debt on our Consolidated Balance Sheet as of December 31, 2008 and 2007, is $500 million aggregate principal amount of the Junior Notes. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the 50% equity credit the majority of rating agencies currently attribute to the Junior Notes.
The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.
As described in Note J -- Common Equity, in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.
Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and the debt securities and preferred stock of our subsidiaries by S&P, Moody's and Fitch as of December 31, 2008:
In July 2008, S&P affirmed the corporate credit ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation and changed the ratings outlooks assigned each company from stable to positive.
On April 30, 2008, Fitch affirmed the ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation and the stable ratings outlook of Wisconsin Electric and Wisconsin Gas. Fitch also revised the ratings outlook of Wisconsin Energy and Wisconsin Energy Capital Corporation from negative to stable.
The security rating outlooks assigned by Moody's for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are all stable.
Subject to other factors affecting the credit markets as a whole, we believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
Capital Requirements
Our estimated 2009, 2010 and 2011 capital expenditures are as follows:
Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact our utility energy segments, future long-term capital requirements may vary from recent capital requirements.
The expected decline in the We Power capital expenditures reflects the anticipated completion of the new Oak Creek units in 2010. The expected increase in the Utility capital expenditures is related to the AQCS project at Oak Creek that is projected to be completed in 2012 and the Glacier Hills Wind Park that is also expected to be completed by 2012.
Investments in Outside Trusts: We have funded our pension obligations and certain other post-retirement obligations in outside trusts. Collectively, these trusts had investments of approximately $878 million as of December 31, 2008. These trusts hold investments that are subject to the volatility of the stock market and interest rates.
We have defined benefit pension plans that cover substantially all of our employees. During 2008, we contributed $38.6 million to our qualified pension plan. As of December 31, 2008, the returns on our pension plan assets were significantly below our expected annual returns of 8.5%. In January 2009, we contributed $270 million to our qualified pension plan. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For further information see Note O -- Benefits in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note P -- Guarantees in the Notes to Consolidated Financial Statements.
We have identified two tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of these two variable interest entities as defined by FIN 46. As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other contract as an operating lease, and both are reflected in the Contractual Obligations/Commercial Commitments table below. A similar power purchase agreement expired during the second quarter of 2008. For additional information, see Note G -- Variable Interest Entities in the Notes to Consolidated Financial Statements.
Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2008:
(a)
The amounts included in the table are calculated using current market prices, forward curves and other estimates. Contracts with multiple unknown variables have been omitted from the analysis.
(b)
Principal and interest payments on Long-Term Debt (excluding capital lease obligations). For the purpose of determining our contractual obligations and commercial commitments only, we assumed the Junior Notes would be retired in 2017 with the proceeds from the issuance of qualifying securities pursuant to the terms of the RCC.
(c)
Capital Lease Obligations of Wisconsin Electric for power purchase commitments.
(d)
Operating Lease Obligations for power purchase commitments and vehicle and rail car leases.
(e)
Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation related to utility operations and for construction, information technology and other services for utility and We Power operations. This includes the power purchase agreement for all of the energy produced by Point Beach.
(f)
Other Long-Term Liabilities includes the expected 2009 supplemental executive retirement plan obligation and the non-discretionary pension contribution. For additional information on employer contributions to our benefit plans see Note O -- Benefits in the Notes to Consolidated Financial Statements.
The table above does not include FIN 48 liabilities. For further information regarding FIN 48 liabilities, refer to Note H -- Income Taxes in the Notes to Consolidated Financial Statements in this report.
Obligations for utility operations have historically been included as part of the rate making process and therefore are generally recoverable from customers. For a discussion of 2009, 2010 and 2011 estimated capital expenditures, see Capital Requirements above.
FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES
MARKET RISKS AND OTHER SIGNIFICANT RISKS
We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Large Construction Projects: In November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615 MW super critical pulverized coal generating units adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including a target construction cost of the Oak Creek expansion of $2.191 billion, plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see Power the Future -- Oak Creek Expansion.
Large construction projects of this type are subject to usual construction risks over which we 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, legal challenges, changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the courts or permitting agencies, the inability to obtain necessary operating permits in a timely manner, other governmental actions and events in the global economy. See Power the Future -- Oak Creek Expansion below for a discussion of claims for schedule and cost relief submitted by Bechtel.
If final costs of the Oak Creek expansion are within 5% of the target cost, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extenuating circumstances, such as force majeure conditions.
Regulatory Recovery: Our utility energy segment accounts for its regulated operations in accordance with SFAS 71. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. Under SFAS 71, we record these items as regulatory liabilities.
Commodity Prices: In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas, purchased power and fuel oil used in the delivery of coal. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas and fuel oil. In addition, we manage the risk of price volatility by utilizing gas and electric hedging programs.
Wisconsin's retail electric fuel cost adjustment procedure mitigates some of Wisconsin Electric's risk of electric fuel cost fluctuation. If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range (plus or minus 2% for 2009) when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted prospectively. For information regarding the current fuel rules, see Utility Rates and Regulatory Matters.
The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for our gas utility operations through GCRMs, which mitigates most of the risk of gas cost variations. For information concerning the natural gas utilities' GCRMs, see Utility Rates and Regulatory Matters.
Natural Gas Costs: Significant volatility in the cost of natural gas affects our electric and gas utility operations. Although the cost of natural gas has decreased recently, natural gas costs have generally increased since 2003. 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 resources are developed.
Higher natural gas costs increase our working capital requirements and result in higher gross receipts taxes in the state of Wisconsin. Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Because federal and state energy assistance dollars have not kept pace with rising natural gas costs over the recent year, our risks related to bad debt expenses have increased.
In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceeds amounts allowed in rates. In July 2008, we filed an application with the PSCW for a three year extension of use of the escrow method for bad debt costs. In December
2008, the PSCW approved a one year extension of use of the escrow method of accounting for bad debt costs through March 2010.
As a result of GCRMs, our gas distribution subsidiaries receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins.
Weather: Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric's electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in the utility segment's service territory during 2008, 2007 and 2006, as measured by degree-days, may be found above in Results of Operations.
Interest Rate: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding as of December 31, 2008. Borrowing levels under these arrangements vary from period to period depending on capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.
We performed an interest rate sensitivity analysis at December 31, 2008 of our outstanding portfolio of $602.3 million of short-term debt with a weighted average interest rate of 4.01% and $424.4 million of variable-rate long-term debt with a weighted average interest rate of 2.48%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $6.0 million before taxes from short-term borrowings and $4.0 million before taxes from variable rate long-term debt outstanding.
Marketable Securities Return: We fund our pension and OPEB obligations through various trust funds, which in turn invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by changes in the market price of trust fund assets. We expect that the risk of expense and contribution variations as a result of changes in the market price of trust fund assets would be mitigated in part through future rate actions by our various utility regulators.
At December 31, 2008, we held the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments:
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. Qualified external investment managers are engaged to manage the investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor. The current study for the pension fund projects long-term annualized returns of approximately 8.25%.
Credit Ratings: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment only in the event of a credit rating change to below investment grade. As of December 31, 2008, we estimate that the collateral or the termination payment required under these agreements totaled approximately $166.5 million. In addition, we have commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.
Economic Conditions: We are exposed to market risks in the regional midwest economy for our utility energy segment. Although the economy in our service territories has not been hit as hard as in other parts of the country, we are beginning to see an increase in unemployment and declines in industrial production demand. We expect the weakening economy to negatively impact our utility sales growth and bad debt levels.
Inflation: We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance and new generation in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Risk Factors in Item 1A.
POWER THE FUTURE
Under our PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. We Power will lease the new plants to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates.
The PTF units include PWGS 1, PWGS 2, OC 1 and OC 2. The following table identifies certain key items related to the units:
(a)
Authorized cash costs represent the PSCW approved costs and the increases for factors such as inflation as identified in the PSCW approved lease terms and adjusted for our ownership percentages in the case of OC 1 and OC 2.
The lease payments are based on the cash costs authorized by the PSCW. Under the lease terms, our return is calculated using a 12.7% return on equity and the equity ratio is assumed to be 53% for the PWGS Units and 55% for the OC Units. The interest component of the return is determined up to 180 days prior to the date that the units are placed in service.
Power the Future - Port Washington
Background: In December 2002, the PSCW issued a written order (the Port Order) granting a CPCN for the construction of PWGS consisting of two 545 MW natural gas-fired combined cycle generating units on the site of Wisconsin Electric's existing Port Washington Power Plant, the natural gas lateral to supply the new plant, and the transmission system upgrades required of ATC. Wisconsin Gas completed construction of the natural gas lateral in December 2004. We Power completed construction of PWGS 1 and PWGS 2 within the PSCW approved cost parameters and the units were placed in service in July 2005 and May 2008, respectively.
Lease Terms: The PSCW approved the lease agreements and related documents under which Wisconsin Electric will staff, operate and maintain PWGS 1 and PWGS 2. Key terms of the leased generation contracts include:
Initial lease term of 25 years with the potential for subsequent renewals at reduced rates;
Cost recovery over a 25 year period on a mortgage basis amortization schedule;
Imputed capital structure of 53% equity, 47% debt;
Authorized rate of return of 12.7% after tax on equity;
Fixed construction cost of PWGS 1 and PWGS 2 at $309.6 million and $280.3 million (2001 dollars) subject to escalation at the GDP inflation rate;
Recovery of carrying costs during construction; and
Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the Port Order, which do not include the key financial terms.
Legal and Regulatory Matters: As a result of the enactment of the Energy Policy Act, FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation). Under FERC's rules implementing the Energy Policy Act, Wisconsin Energy, Wisconsin Electric and We Power filed a joint application for FERC authorization to transfer the generating assets and limited interconnection facilities of PWGS 2 through a lease arrangement between We Power and Wisconsin Electric. We received approval from FERC for this asset transfer in December 2006.
Power the Future - Oak Creek Expansion
Background: In November 2003, the PSCW issued an order (the Oak Creek Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of two 615 MW coal-fired units (the Oak Creek expansion) to be located adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. OC 1 is scheduled to be operational in late 2009 and OC 2 is scheduled to be operational in fall 2010. The Oak Creek Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the State. The total cost for the two units was set at $2.191 billion, and the order provided for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extenuating circumstances, such as force majeure conditions. The CPCN was granted contingent upon us obtaining the necessary environmental permits. All necessary permits have been received at this time. In June 2005, construction commenced at the site. In November 2005, we completed the sale of approximately a 17% interest in the project to two unaffiliated entities, who will share ratably in the construction costs.
The Oak Creek expansion includes a new coal handling system that will serve both the existing units at Oak Creek and OC 1 and OC 2. The new coal handling system was placed into service during the fourth quarter of 2007 at a cost of approximately $175.0 million. A total of $24.1 million of additional costs related to the coal handling system were incurred during 2008. The most significant component of this additional cost was the rail cars that will supply coal to OC 1 and OC 2.
The Oak Creek expansion also includes a new water intake system that will serve both the existing units at Oak Creek and OC 1 and OC 2. The new water intake system was placed into service in January 2009 at a cost of approximately $133.0 million.
Lease Terms: In October 2004, the PSCW approved the lease generation contracts between Wisconsin Electric and We Power for the Oak Creek expansion. Key terms of the leased generation contracts include:
Initial lease term of 30 years with the potential for subsequent renewals at reduced rates;
Cost recovery over a 30 year period on a mortgage basis amortization schedule with the potential for subsequent renewals at reduced rates;
Imputed capital structure of 55% equity, 45% debt;
Authorized rate of return of 12.7% after tax on equity;
Recovery of carrying costs during construction; and
Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the Oak Creek Order, which do not include the key financial terms.
Construction Status: In July 2008, Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, notified us in a letter that it forecasts the in-service date of unit 1 to be delayed three months beyond the guaranteed contract date of September 29, 2009. Bechtel also advised us in the letter that it forecasts the in-service date of unit 2 to be one month earlier than the guaranteed contract date of September 29, 2010.
According to the letter, reasons for the delay of unit 1 include severe winter weather experienced during the winters of 2006-2007 and 2007-2008, exacerbated by severe rain storms in April and June of 2008, changes in local labor conditions from those anticipated by Bechtel, the cumulative impact of a large number of change orders and delay in receiving FNTP in 2005 as a result of the court challenges by certain opposition groups to the CPCN for the Oak Creek expansion. Bechtel advised that they expected to submit a claim for cost and schedule relief associated with these issues by the end of 2008.
Based on Bechtel's earlier communications, we notified Bechtel on September 29, 2008 that we were invoking the formal dispute resolution process provided in the contract in order to resolve certain issues related to the rights of the parties under the contract.
We received Bechtel's claims for schedule and cost relief on December 22, 2008. Bechtel continues to target an in-service date for unit 1 three months beyond the guaranteed contract date of September 29, 2009, and an in-service date for unit 2 one month earlier than the guaranteed contract date of September 29, 2010. However, Bechtel does request schedule relief that would result in six months of relief from liquidated damages beyond the guaranteed contract date for unit 1 and three months of relief from liquidated damages beyond the guaranteed contract date for unit 2.
Bechtel's first claim is based on the alleged impact of severe weather and certain labor-related matters. Bechtel is requesting approximately $413 million in costs related to changed weather and labor conditions. Although Bechtel has reserved the right to request future additional costs and schedule relief, this amount includes $45 million of projected future costs in addition to those already incurred.
The weather events for which Bechtel seeks cost and schedule relief are (i) extreme winds from September 2006 through April 2007, (ii) snowstorms from December 2007 through April 2008, and (iii) rain storms in June 2008. Bechtel contends that these weather events constituted events of force majeure. We will conduct a detailed analysis of Bechtel's force majeure claim to determine whether Bechtel is entitled to any schedule relief as a result of these weather events. We believe Bechtel's request for cost relief related to its claim of force majeure is without merit. Bechtel also claims that these same weather events constituted changed local conditions that it could not have reasonably foreseen and that caused it to incur additional costs. We believe that the claim for additional costs and schedule relief based on a change in local conditions is without merit.
The alleged changes in labor conditions for which Bechtel seeks cost and schedule relief are (i) a significant shortage in the availability of craft labor, (ii) significant increases in competing projects, (iii) the overtime and per diems allegedly necessary to attract labor, and (iv) alleged restrictions that our Project Labor Agreement placed on Bechtel's ability to attract and retain craft labor. Bechtel describes these as changed local conditions for which it believes we should bear the risk. Under the terms of the contract, we agreed to accept labor-related risk only as to wage escalation in excess of 4% annually as measured by published wage bulletins. Therefore, we believe that this claim is without merit.
Bechtel's second claim of approximately $72 million seeks cost and schedule relief for the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the FNTP in July 2005 as follows: (i) the delay in issuing certain limited notices to proceed; (ii) the delay in issuing the FNTP until the final resolution of litigation brought by certain opposition groups that challenged the CPCN for the Oak Creek expansion; (iii) the imposition of additional limits to third party cancellation charges which allegedly restricted Bechtel's ability to issue purchase orders; (iv) the reduction of the pre-FNTP monthly payments below the amounts required by the contract; and (v) the request by ERS to perform design studies and issue design changes during the pre-FNTP period. We believe that this claim is without merit. We believe Bechtel was fully compensated for any and all impacts of the delayed start as indicated in certain change orders entered into between ERS and Bechtel prior to the start of construction of the Oak Creek expansion. Further, we do not believe that the contract provides for relief based upon the cumulative impact of change orders.
We continue to believe that the only circumstances and events for which we currently retain price adjustment risk under the contract are force majeure, wage escalation in excess of 4% annually as measured by published wage bulletins, delays caused by us, changes in scope or performance requested by us and unforeseen sub-surface ground conditions.
We are currently in the mediation phase with respect to determining the parties' rights under the contract and Bechtel's claims. We are currently unable to predict the ultimate outcome of the claims.
We estimate that for each month of delay of the in-service date of unit 1 beyond September 29, 2009, earnings for 2009 would be reduced by $0.03 per share after-tax compared to what they otherwise would have been. In addition, we estimate that for each month of acceleration of the in-service date of unit 2 in advance of September 29, 2010, earnings for 2010 would increase by $0.02 per share after-tax compared to what they otherwise would have been.
WPDES Permit: In March 2007, on appeal, the Dane County Circuit Court affirmed in part an earlier decision by an ALJ in a contested case hearing, to uphold the WDNR's issuance of the WPDES permit. The Court also
remanded certain aspects of the ALJ's decision for further consideration based on the January 2007 decision by the United States Court of Appeals for the Second Circuit that found certain portions of the federal rule concerning water intake systems for existing facilities (the Phase II Rule) impermissible and remanded several parts of the rule to the EPA for further consideration or potential rulemaking. In July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems for existing facilities.
In November 2007, the ALJ determined that the Oak Creek expansion units were new facilities under Section 316(b) of the Clean Water Act. The ALJ remanded the WPDES permit to the WDNR and directed the WDNR to reissue or modify the permit to reflect "best technology available" to comply with the standards applicable to new facilities under Wisconsin state law. In July 2008, the WDNR issued the final modified permit. The time period for any party to challenge the modified WPDES permit has expired.
In July 2008, we and the other two joint owners of the Oak Creek expansion reached an agreement with Clean Wisconsin, Inc. and Sierra Club, the groups who were opposing the WPDES permit. Under the settlement agreement, these groups agreed to withdraw their opposition to the modified WPDES permit for the existing and expansion units at Oak Creek.
In the agreement with Clean Wisconsin, Inc. and Sierra Club, we committed to contribute our share of $5 million (approximately $4.2 million) towards projects to reduce greenhouse gas emissions. We also agreed (i) for the 25 year period ending 2034, subject to regulatory approval and cost recovery, to contribute our share of up to $4 million per year (approximately $3.3 million) to fund projects to address Lake Michigan water quality, and (ii) subject to regulatory approval and cost recovery, to develop new solar and biomass generation projects. We also agreed to support state legislation to increase the renewable portfolio standard to 10 percent by 2013 and 25 percent by 2025, and to retire 116 MW of coal-fired generation at our Presque Isle Power Plant.
Other Regulatory Matters: As a result of the enactment of the Energy Policy Act, FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation). Under FERC's rules implementing the Energy Policy Act, Wisconsin Energy, Wisconsin Electric and We Power filed a joint application for FERC authorization to transfer the generating assets and limited interconnection facilities of OC 1 and OC 2 through a lease arrangement between We Power and Wisconsin Electric. We received approval from FERC on these leases in December 2006.
UTILITY RATES AND REGULATORY MATTERS
The PSCW regulates our retail electric, natural gas, steam and water rates in the state of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The MPSC regulates our retail electric rates in the state of Michigan. Within our regulated segment, we estimate that approximately 90% of our electric revenues are regulated by the PSCW, 6% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. All of our natural gas, steam and water revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.
The table below summarizes the anticipated annualized revenue impact of the recent Wisconsin Electric rate changes:
2008 Pricing: During 2007, Wisconsin Electric and Wisconsin Gas initiated rate proceedings. Wisconsin Electric asked the PSCW to approve a comprehensive plan which would result in price increases of $648.6 million for its electric customers in Wisconsin. This price increase would be reduced by expected bill credits resulting from the sale of Point Beach. The initial rate filing estimated bill credits of $371.0 million in 2008 and $187.5 million in 2009, resulting in net pricing increases of 7.5% in 2008 and 7.5% in 2009. In addition, Wisconsin Electric requested a 1.8% price increase in 2008 for its gas customers and an approximately 16.0% price increase in 2008 for all steam customers in metropolitan Milwaukee. Wisconsin Gas filed for a 4.1% price increase in 2008 for its gas customers.
Electric pricing increases were needed to allow us to continue progress on previously approved initiatives, including: costs associated with our new PTF plants; recovery of costs associated with transmission; compliance with environmental regulations; continuation of investment in renewable and efficiency programs, including the Blue Sky Green Field wind project; and scheduled recovery of regulatory assets.
On January 17, 2008, the PSCW approved pricing increases for Wisconsin Electric and Wisconsin Gas as follows:
$389.1 million (17.2%) in electric rates for Wisconsin Electric - the pricing increase will be offset by $315.9 million in bill credits in 2008 and $240.7 million in bill credits in 2009, resulting in a net increase of $73.2 million (3.2%) and $75.2 million (3.2%), respectively;
$4.0 million (0.6%) for natural gas service from Wisconsin Electric;
$3.6 million (11.2%) for steam service from Wisconsin Electric; and
$20.1 million (2.2%) for natural gas service from Wisconsin Gas.
In addition, the PSCW lowered the return on equity for Wisconsin Electric and Wisconsin Gas from 11.2% to 10.75%. The PSCW also determined that $85.0 million of the Point Beach proceeds should be immediately applied to offset certain regulatory assets.
Wisconsin Electric expects to provide a total of approximately $710.0 million of bill credits to its Wisconsin customers over the three year period ending December 31, 2010. As of December 31, 2008, we have issued approximately $296.4 million to Wisconsin retail customers.
Michigan Price Increase: In January, 2008, Wisconsin Electric filed a rate increase request with the MPSC. This request represents an increase in electric rates of 14.7%, or $22.0 million, to support the growing demand for electricity, continued investment in renewable programs, compliance with environmental regulations, addition of distribution infrastructure and increased operational expenses. In November 2008, a settlement agreement with the MPSC staff and intervenors for a rate increase of $7.2 million, or 4.6%, was approved by the MPSC, effective January 1, 2009.
2006 Pricing: In January 2006, Wisconsin Electric received an order from the PSCW that allowed it to increase annual electric revenues by approximately $222.0 million, or 10.6%, to recover increased costs associated with investments in our PTF units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The rate increase was based on an authorized return on equity of 11.2%. The order also required Wisconsin Electric to refund to customers, with interest, any fuel revenues that it receives that are in excess of fuel and purchased power costs that it incurs, as defined by the Wisconsin fuel rules. The original order stipulated that any refund would also include interest at short-term rates. This refund provision did not extend past December 31, 2006.
During 2006, we experienced lower than expected fuel and purchased power costs. In September 2006, we requested and received approval from the PSCW to refund favorable fuel recoveries including accrued interest at a short-term rate. In addition, in September 2006 the PSCW determined that if the total recoveries for 2006 exceeded $36 million, interest on the amount in excess of $36 million would be paid at the rate of 11.2%, our authorized return on equity rather than at short-term rates as originally set forth in the order. During October 2006, we refunded $28.7 million, including interest, to Wisconsin retail customers as a credit on their bill and we received approval from the PSCW to refund an additional $10 million, including interest, in the first quarter of 2007.
Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for increases in gas revenues totaling $60.1 million ($21.4 million, or 2.9%, for Wisconsin Electric gas operations and $38.7 million, or 3.7%, for Wisconsin Gas gas operations). The rate increases were based on an authorized return on equity of 11.2% for the gas operations of both Wisconsin Electric and Wisconsin Gas.
The steam rate proceeding was a traditional rate proceeding. The January 2006 order provided for an increase in steam rates of $7.8 million, or 31.5%, to be phased in over a two year period beginning in 2006. The rate increase was based on an authorized return on equity of 11.2%.
2010 Pricing: We anticipate filing rate cases for Wisconsin Electric and Wisconsin Gas in the first half of 2009 for new rates effective in January 2010.
Limited Rate Adjustment Requests
2008 Fuel Recovery Request: In March 2008, Wisconsin Electric filed a rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel costs was being driven primarily by increases in the price of natural gas and the higher cost of transporting coal by rail as a result of increases in the cost of diesel fuel. On April 11, 2008, the PSCW approved an annual increase of $76.9 million (3.3%) in Wisconsin retail electric rates on an interim basis. In July 2008, we received the final rate order, which authorized an additional $42.0 million in rate increases, for a total increase of $118.9 million (5.1%). Any over-collection of fuel surcharge revenue in calendar year 2008 was subject to refund with interest at a rate of 10.75%. During the first quarter of 2009, we expect to refund approximately $8.6 million, including interest, to Wisconsin retail customers related to the over-collection of fuel costs in 2008.
Other Utility Rate Matters
Oak Creek Air Quality Control System Approval: As anticipated, in July 2008 we received approval from the PSCW granting Wisconsin Electric authority to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant Units 5-8. Construction of these emission controls began in late July 2008, and we expect the installation to be completed during 2012. We originally estimated the cost of this project to be $830 million, including AFUDC ($750 million excluding AFUDC). We now expect the cost of completing this project to be approximately $885 million, including AFUDC ($800 million excluding AFUDC). The cost increase is primarily attributable to increases in material prices that occurred prior to the commencement of construction and material procurement activities in July 2008. The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree with the EPA. The Citizens Utility Board and Clean Wisconsin Inc., the two groups that opposed controlling Oak Creek Power Plant Units 5-8, petitioned the PSCW for rehearing and reconsideration of its order. The PSCW denied their request and the petitioners did not appeal the PSCW's decision.
Michigan Legislation: During October 2008, Michigan enacted legislation to make significant changes in regulatory procedures, which should provide for more timely cost recovery. Public Act 286 allows the use of a forward-looking test year in rate cases rather than historical data, and allows us to put interim rates into effect six months after filing a complete case. Rate filings for which an order is not issued within 12 months are deemed approved. In addition, we could seek a CPCN for new investment, and could recover interest on the investment during construction. Public Act 286 also gives the MPSC expanded authority over proposed mergers and acquisitions, and requires action within 180 days of filing. In addition, Public Act 295 calls for the implementation of a renewable portfolio standard of 10% by 2015, and energy optimization (efficiency) targets up to 1% annually by 2015. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards, and provides for ongoing review and revision to assure the measures taken are cost-effective.
Fuel Cost Adjustment Procedure: Within the state of Wisconsin, Wisconsin Electric operates under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. Embedded within its base rates is an amount to recover fuel costs. Under the current fuel rules, no adjustments are made to rates as long as fuel and purchased power costs are expected to be within a band of the costs embedded in current rates for the twelve month period ending December 31. If, however, annual fuel costs are expected to fall outside of the band, and actual costs fall outside of established fuel bands, then we may file for a change in fuel recoveries on a prospective basis.
In June 2006, the PSCW opened a docket (01-AC-224) to consider revisions to the existing fuel rules (Chapter PSC 116). Public comments from stakeholders, including regulated utilities, were received by the PSCW. In July 2008, the PSCW ordered a second comment period on a revised rule, and hearings were held in August 2008. The current version of the revised rule recommends modifications to allow for annual plan and reconciliation filings of fuel costs by each regulated utility. In the period between plan and reconciliation, escrow accounting would be used to record fuel costs outside a plus or minus 2% annual band of the total fuel costs allowed in rates. The proposed rule further recommends that the escrow balance be trued-up annually following the end of each calendar year. The earliest that we expect any possible action on the fuel rules is the summer of 2009.
Edison Sault and Wisconsin Electric's operations in Michigan operate under a Power Supply Cost Recovery mechanism which generally allows for the recovery of fuel and purchased power costs on a dollar for dollar basis.
Electric Transmission Cost Recovery: Wisconsin Electric divested its transmission assets with the formation of ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within ATC and increased transmission infrastructure requirements in the state. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed us to use escrow accounting whereby we defer transmission costs that exceed amounts embedded in our rates. We are allowed to earn a return on the unrecovered transmission costs we deferred at our weighted average cost of capital. As of December 31, 2008, we have deferred $199 million of unrecovered transmission costs. The January 2008 rate order provided for the recovery of these costs over six years beginning in January 2008; and the escrow accounting treatment has been discontinued.
Gas Cost Recovery Mechanism: Our natural gas operations operate under GCRMs as approved by the PSCW. Generally, the GCRMs allow for a dollar for dollar recovery of gas costs. There is an incentive mechanism under the GCRMs which allows for increased revenues if we acquire gas lower than benchmarks approved by the PSCW. During 2008, approximately $2.6 million of additional revenues were earned. During 2007 and 2006, no additional revenues were earned under the incentive portion of the GCRMs.
Bad Debt Costs: In January 2006, the PSCW issued an order approving the amortization over the next five years of bad debts deferred in 2004 for our gas operations. The bad debts deferred in 2004 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.
In March 2005, the PSCW approved our use of escrow accounting for residential bad debt costs. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds amounts allowed in rates. As a result of this approval from the PSCW, which extends through March 2009, we escrowed approximately $8.1 million, $8.9 million and $3.7 million in 2008, 2007 and 2006, respectively, related to bad debt costs. In July 2008, we filed an application with the PSCW for a three year extension of use of the escrow
method for bad debt costs. In December 2008, the PSCW approved a year extension for the use of escrow method of accounting for bad debt costs through March 2010.
MISO Energy Markets: The PSCW approved deferral treatment for our costs related to the implementation of the MISO Energy Markets. Amounts deferred through December 31, 2007 are being recovered in rates. For additional information, see Industry Restructuring and Competition -- Electric Transmission and Energy Markets.
Coal Generation Forced Outage - 2007: In March 2007, we requested and received approval from the PSCW to defer as a regulatory asset approximately $13.2 million related to replacement power costs due to a forced outage of Unit 1 at the Pleasant Prairie Power Plant. The outage extended from February 2007 through March 2007. These costs were recovered as part of the $85 million one-time recovery using Point Beach proceeds pursuant to the 2008 rate order in a write-off during the first quarter of 2008.
Wholesale Electric Pricing: In August 2006, Wisconsin Electric filed a wholesale rate case with FERC. The filing requested an annual increase in rates of approximately $16.7 million applicable to four existing wholesale electric customers. This includes a mechanism for fuel and other cost adjustments. In November 2006, FERC approved the rate filing subject to refund with interest. Three of the existing customers' rates were effective in January 2007. The remaining wholesale customer's rates were effective in May 2007. FERC approved a settlement of the rate filing in September 2007.
In August 2008, we issued a one-time $62.5 million refund to our wholesale customers pursuant to a FERC approved settlement related to the sale of Point Beach.
Depreciation Rates: Periodically, we engage consultants to perform depreciation studies on our utility assets to determine our depreciation rates. In 2008, a consultant completed a depreciation study that concluded that we should reduce our utility depreciation rates because of longer asset lives and increased salvage values. The consultant estimated that the new proposed rates would reduce annual depreciation expense by approximately $55 million. In January 2009, we filed the depreciation study with the PSCW. If the PSCW approves the depreciation study, we would expect to implement the new depreciation rates in late 2009. We do not expect the new depreciation rates to have a material impact on earnings because we anticipate that the new depreciation rates will be considered when the PSCW sets our 2010 electric and gas prices. For information on our current depreciation rates, see Note A -- Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.
Renewables, Efficiency and Conservation: In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Wisconsin Electric's baseline renewable energy percentage is 2.27%. Act 141 provides that for the years 2006-2009, Wisconsin Electric may not decrease its renewable energy percentage, and for the years 2010-2014, it must increase its renewable energy percentage at least two percentage points to a level of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Assuming the bulk of additional renewables is wind generation, Wisconsin Electric must obtain approximately 362 MW of additional renewable capacity by 2012 and another approximately 300 MW of additional renewable capacity by 2015 to meet the requirements of Act 141. We have already started development of additional sources of renewable energy which will assist us in complying with Act 141. See Wind Generation discussion below.
In 2008, the Governor of Wisconsin established the Governor's Task Force on Global Warming. The Task Force issued its final report in July 2008 that includes an increased renewable portfolio standard. Pursuant to the Task Force's recommendations, the renewable portfolio standard would increase to 10% by 2013, 20% by 2020 and 25% by 2025. The legislature is expected to review these recommendations in 2009.
Act 141 allows the PSCW to delay a utility's implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would result in unreasonable rate increases or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities. The previous law did not include similar provisions. Act 141 provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility may not
be ordered to achieve additional energy conservation or efficiency. Prior to Act 141, there had been no agreement on how to determine compliance with the Energy Priorities law, which provides that it is the policy of the PSCW, to the extent it is cost-effective and technically feasible, to consider the following options in the listed order when reviewing energy-related applications: (1) energy conservation and efficiency, (2) noncombustible renewable energy resources, (3) combustible renewable energy resources, (4) natural gas, (5) oil or low sulfur coal and (6) high sulfur coal and other carbon-based fuels.
Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the DOA back to the PSCW and/or contracted third parties. In addition, Act 141 requires that 1.2% of utilities' annual operating revenues be used to fund these programs. The Governor of Wisconsin's Task Force on Global Warming recommended in July 2008 that this amount be increased to approximately 4%. It is not known at this time if that recommendation will be implemented.
Public Act 295 enacted in Michigan calls for the implementation of a renewable portfolio standard by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
Wind Generation: In June 2005, we purchased the development rights to a wind farm project (Blue Sky Green Field) from Navitas Energy, Inc. We began construction in June 2007 and the project reached commercial operation in May 2008. Land restoration, road repairs and other post construction activities are near completion. The cost of this project was approximately $301.7 million, including AFUDC, as of December 31, 2008.
In addition, in October 2007 we provided notice to FPL Energy, a subsidiary of FPL, that we were exercising the option we received in connection with the sale of Point Beach to purchase all rights to a new wind farm site in central Wisconsin, Glacier Hills Wind Park. In July 2008, the purchase was completed and in October 2008, we filed a request for a CPCN with the PSCW for the Glacier Hills Wind Park. We currently expect to install wind turbines with approximately 132 to 207 MW of generating capacity, subject to the final site configuration and the turbine equipment selected. We expect 2012 to be the first full year of operation, subject to regulatory approvals and turbine availability.
ELECTRIC SYSTEM RELIABILITY
In response to customer demand for higher quality power required by modern equipment, we are evaluating and updating our electric distribution system. We are taking steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability. These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near-term efforts to enhance our current electric distribution infrastructure. For the long-term, we have developed a distribution system asset management strategy that requires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy.
We had adequate capacity to meet all of our firm electric load obligations during 2008 and 2007. All of our generating plants performed well during the warmest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required and we did not interrupt or curtail service to non-firm customers who participate in load management programs.
We expect to have adequate capacity to meet all of our firm load obligations during 2009. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures as we have in past years.
ENVIRONMENTAL MATTERS
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation challenges related to current and past operations. Specific environmental issues affecting our utility and non-utility energy segments include but are not limited to (1) air emissions such as CO2, SO2, NOx, small
particulates and mercury, (2) disposal of combustion by-products such as fly ash and (3) remediation of former manufactured gas plant sites.
We are currently pursuing a proactive strategy to manage our environmental issues including (1) improving our overall energy portfolio by adding more efficient generation as part of our PTF strategy, (2) developing additional sources of renewable electric energy supply, (3) reviewing water quality matters such as discharge limits and cooling water requirements, (4) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules, (5) entering into agreement with the EPA to reduce emissions of SO2 and NOx by more than 65% by 2013, (6) evaluating and implementing improvements to our cooling water intake systems, (7) continuing the beneficial re-use of ash and other solid products from coal-fired generating units and (8) conducting the clean-up of former manufactured gas plant sites. The capital cost of implementing the EPA Consent Decree is estimated to be approximately $1.2 billion over the 10 years ending 2013. These costs are principally associated with the installation of air quality controls on Pleasant Prairie Units 1 and 2 and Oak Creek Units 5-8. In June 2007, we submitted an application to the PSCW requesting approval to construct environmental controls at Oak Creek Units 5-8 by 2012 as required by the Consent Decree. We expect the cost of completing this project to be approximately $885 million, including AFUDC. Through December 31, 2008, we have spent approximately $506.7 million associated with implementing the EPA Consent Decree. For further information concerning the Consent Decree, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in this report.
National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the NAAQS for 1-hour ozone. In 2004, the EPA began implementing NAAQS for 8-hour ozone and PM2.5. In December 2006, the EPA further revised the PM2.5 standard, and in March 2008, the EPA announced its decision to further lower the 8-hour ozone standard.
8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in southeastern Wisconsin as non-attainment areas for the 8-hour ozone NAAQS. States were required to develop and submit SIPs to the EPA by June 2007 to demonstrate how they intended to comply with the 8-hour ozone NAAQS. Instead of submitting a SIP, Wisconsin submitted a request to redesignate all counties in southeastern Wisconsin to be in attainment with the standard. In addition to the request for redesignation, Wisconsin also adopted the RACT rule that applies to emissions from our power plants in the affected areas of Wisconsin. We believe compliance with the NOx emission reduction requirements under the Consent Decree will substantially mitigate costs to comply with the RACT rule. In March 2008, the EPA issued a determination that the state of Wisconsin had failed to submit a SIP. We do not anticipate any further requirements to reduce emissions as a result of this finding, but we are unable to predict that outcome until Wisconsin responds to this finding (expected in July 2009) and the EPA subsequently takes a final approval action. In March 2008, the EPA announced its decision to further lower the 8-hour standard. Although additional counties may be designated as non-attainment areas under the revised standard, until those designations become final and until any potential additional rules are adopted, we are unable to predict the impact on the operation of our existing coal-fired generation facilities.
PM2.5 Standard: In December 2004, the EPA designated PM2.5 non-attainment areas in the country. All counties in Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. In December 2006, a more restrictive federal standard became effective; however, on February 24, 2009 the D.C. Circuit Court of Appeals issued a decision on the revised standard and remanded it back to the EPA for revision. The court's decision will likely result in an even more stringent annual PM2.5 standard. Until such time as the EPA revises the standard consistent with the court's decision and the states develop rules and submit SIPs to the EPA to demonstrate how they intend to comply with the standard, we are unable to predict the impact of this more restrictive standard on the operation of our existing coal-fired generation facilities or our new PTF generating units being leased by Wisconsin Electric including OC 1, OC 2 and PWGS.
Clean Air Interstate Rule: The EPA issued the final CAIR in March 2005 to facilitate the states in meeting the 8-hour ozone and PM2.5 standards by addressing the regional transport of SO2 and NOx. CAIR required NOx and SO2 emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. CAIR was to be implemented in two phases. Overall, CAIR is expected to result in a 70% reduction in SO2 emissions and a 65% reduction in NOx emissions from 2002 emission levels. A final CAIR rule was adopted in Wisconsin and Michigan. Subsequently, in
July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAIR and determined that the EPA must promulgate a rule consistent with its decision, but did not issue a mandate that would put its ruling into effect. In December 2008, the Court remanded CAIR to the EPA, but did not vacate it. Therefore, CAIR will remain in place while the EPA drafts a replacement rule. The Court's decision did not include a deadline for the replacement rule. We previously determined that compliance with the NOx and SO2 emission reductions requirements under the Consent Decree would substantially mitigate costs to comply with CAIR and will achieve the levels necessary under at least the first phase of CAIR. It will be necessary to see what the revised rule contains before we can determine if any additional reductions will be required.
Clean Air Mercury Rule: The EPA issued the final CAMR in March 2005, following the agency's 2000 regulatory determination that utility mercury emissions should be regulated. CAMR would limit mercury emissions from new and existing coal-fired power plants and cap utility mercury emissions in two phases, applicable in 2010 and 2018. The caps would limit emissions at approximately 20% and ultimately 70% below current utility mercury levels.
The federal rule was challenged by a number of states including Wisconsin and Michigan. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAMR and sent the rule back to the EPA for re-consideration. The D.C. Circuit denied a request for a rehearing and the parties subsequently petitioned the U.S. Supreme Court for review of the D.C. Circuit's decision. In February 2009, the U.S. Supreme Court denied the petition for certiorari. In December 2008, a number of environmental groups also filed a complaint with the D.C. Circuit asking that the court place the EPA on a schedule for promulgating Maximum Achievable Control Technology limits for electric utilities. This latest complaint is still being processed by the D.C. Circuit.
In October 2004, the WDNR issued mercury emission control rules that affect electric utilities in Wisconsin. The Wisconsin rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program and require that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. In March 2007, the WDNR proposed changes to this rule to include an implementation plan for CAMR, along with a proposal for more stringent state-only rules. WDNR did not take any final action on the March 2007 rule proposal.
In March 2008, the WDNR once again proposed changes to the existing state-only mercury rule. In June 2008, the Natural Resources Board approved the proposed rule. The rule was approved and went into effect in December 2008. The new rule requires 90% mercury emission reductions from utilities by 2015, or, under a multi-emission option, 70% reductions by 2015, 80% by 2018 and 90% by 2021, provided utilities meet stringent NOx and SO2 emission reduction requirements by 2015. The rule eliminates the 2008-2009 emission cap, but retains the 40% emission reduction requirement for the period 2010-2014. Our plan is to maximize mercury reductions from our initial emission control investments. Enhanced mercury reductions from refinements to SO2 and NOx controls are expected to be developed over the next several years. Because control technology is under development, it is difficult to estimate what the cost will be to comply with the Wisconsin requirements. We believe the range of possible expenditures could be approximately $50 million to $200 million.
As of January 2008, the MDEQ has also proposed a rule to both implement CAMR and impose state-only requirements for achieving 90% emission reductions in 2015. The MDEQ has revised the draft rule to remove the requirements related to the now vacated CAMR, but is proceeding with the remainder of the state-only rule. As part of a new technology demonstration which we undertook in partnership with the DOE, technology for the control of mercury has been installed at our Presque Isle Power Plant. We plan to continue the operation of that equipment beyond the test period. We anticipate that this equipment will be sufficient to comply with reductions that would be required under the state-only rule.
Clean Air Visibility Rule: The EPA issued CAVR in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines BART requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation's 156 Class I protected areas. States are then required to determine the types of emission controls that those facilities must use to control their emissions. The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia. States were required to submit SIPs to implement CAVR to the EPA by December 2007. Wisconsin has not yet submitted a SIP. Michigan submitted a SIP, which was partially approved. The reductions associated with the state plans are scheduled to begin to take effect in 2014, with full implementation before 2018. In response to a citizen suit, in January 2009, the EPA issued a finding of
failure to 37 states, including Wisconsin and Michigan, regarding their failure to submit SIPs. The finding starts a two-year window for the EPA to issue Federal Implementation Plans, unless a state submits and receives SIP approval. Failure to submit an approved SIP does not initiate any federal sanctions against the states.
Wisconsin and Michigan have completed the BART rules, which cover one aspect of CAVR regulations. Wisconsin BART rules became effective July 2008 and Michigan BART rules became effective in September 2008.
Both Wisconsin and Michigan BART rules are based, in part, on utility reductions of NOx and SO2 that were expected to occur under CAIR. Therefore, we will not be able to determine final impacts of these rules until the EPA completes a new CAIR rule.
Clean Water Act: Section 316(b) of the CWA requires that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there were no federal rules that defined precisely how states and EPA regions determined that an existing intake met BTA requirements. The Phase II rule established, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the 316(b) rules for Wisconsin Electric's Oak Creek Power Plant, We Power's Oak Creek expansion and PWGS were included in project costs.
In January 2007, the Federal Court of Appeals for the Second Circuit issued a decision concerning the Phase II rule for existing facilities (Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) (2d Cir. 2007)). The Second Circuit found certain portions of the rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems. We will work with the relevant state agencies as permits for our facilities come due for renewal to determine what, if any, actions need to be taken. Until the EPA completes its reconsideration and rulemaking, we cannot predict what impact these changes to the federal rules may have on our facilities. For additional information on this matter related to the Oak Creek expansion, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future -- Oak Creek Expansion in this report.
EPA Advance Notice of Proposed Rulemaking: In July 2008, the EPA issued an Advance Notice of Proposed Rulemaking seeking comment on a large array of possible regulatory actions it is contemplating under the federal CAA to reduce greenhouse gas emissions. The proposed rules impact virtually all aspects of the economy including electric and natural gas utilities. The EPA document follows a U.S. Supreme Court decision last year requiring the EPA to regulate greenhouse gas emissions under the CAA if it finds that they endanger public health or welfare. The document seeks comment on whether the EPA should make that finding and, if so, the types of regulations it should adopt. The comment period has closed, and there has been no additional formal activity in the rule process. We cannot predict at this time what impact, if any, such a finding would have on us.
Manufactured Gas Plant Sites: We are voluntarily reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. For further information, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Ash Landfill Sites: We aggressively seek environmentally acceptable, beneficial uses for our combustion byproducts. For further information, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
EPA Consent Decree: In April 2003, Wisconsin Electric and the EPA announced that a Consent Decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007. For further information, see Note S -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Greenhouse Gases: We continue to take measures to reduce our emissions of greenhouse gases. We support flexible, market-based strategies to curb greenhouse gas emissions, including emissions trading, joint implementation projects and credit for early actions. We support a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.
Our emissions in future years will continue to be influenced by several actions completed, planned or underway, including:
Repowering the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
Adding coal-fired units as part of the Oak Creek expansion that will be the most thermally efficient coal units in our system.
Increasing investment in energy efficiency and conservation.
Additional renewable capacity and promoting increased participation in the Energy for Tomorrow® renewable energy program.
Retirement of Coal units 1-4 at the Presque Isle Power Plant.
Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. Legislative proposals that would impose mandatory restrictions on CO2 emissions continue to be considered in the U.S. Congress, and the new President and his administration have made it clear that they are focused on reducing CO2 emissions. Although the ultimate outcome of these efforts cannot be determined at this time, mandatory restrictions on our CO2 emissions could result in significant compliance costs that could affect future results of operations, cash flows and financial condition. For additional information, 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.
LEGAL MATTERS
Arbitration Proceedings: In May 2007, we reached a settlement with our largest electric customers, two iron ore mines, that operate in the Upper Peninsula of Michigan. The mines represent approximately 6.5% of our 2008 electric sales; however, they provide a much smaller percentage of earnings. The mines had special negotiated contracts that expired in December 2007. The contracts had price caps for approximately 80% of the energy sales. We did not recognize revenue on amounts billed that exceeded the price caps.
The incremental power costs in the Upper Peninsula of Michigan are now determined by MISO. In April 2005, we began to bill the mines the incremental power costs as quantified by the MISO Energy Markets. The mines notified us that they were disputing these billings and a portion of these disputed amounts were deposited in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We notified the mines that we believe that they failed to comply with certain notification provisions related to annual production as specified within the contracts.
In May 2007, Wisconsin Electric entered into a settlement agreement with the mines. The settlement was a full and complete resolution of all claims and disputes between the parties for electric service rendered by Wisconsin Electric under the power purchase agreements through March 31, 2007. Pursuant to the settlement, the mines paid Wisconsin Electric approximately $9.0 million and Wisconsin Electric released to the mines all funds held in escrow. The estimated earnings impact of the payment from the mines was $0.04 per share, which was recorded in 2007. The settlement also provided a mutually satisfactory pricing structure through the power purchase agreement expiration date of December 31, 2007. Beginning in January 2008, the mines began receiving electric service from Wisconsin Electric in accordance with tariffs approved by the MPSC.
Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin's investor-owned utilities. The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer. Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.
In recent years, dairy farmers have commenced actions or made claims against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage, and, more recently, ground currents resulting from the operation of its electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. The Wisconsin Supreme Court has rejected the arguments that, if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not be found negligent in stray voltage cases. Additionally, the Court has held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation. As a result of this case, claims
by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW "level of concern."
In December 2008, a stray voltage lawsuit was filed against Wisconsin Electric. We do not believe the lawsuit has merit and we will vigorously defend the case. This lawsuit against Wisconsin Electric is not expected to have a material adverse effect on our financial statements. In June 2007, a stray voltage lawsuit filed against Wisconsin Electric in May 2005 was settled. This settlement did not have a material adverse effect on our financial condition or results of operations. We continue to evaluate various options and strategies to mitigate this risk.
NUCLEAR OPERATIONS
Point Beach Nuclear Plant: Wisconsin Electric previously owned two electric generating units (Unit 1 and Unit 2) at Point Beach in Two Rivers, Wisconsin. During 2007 and 2006 Point Beach provided approximately 17.3% and 25.3% respectively, of our net electric energy supply.
On September 28, 2007, Wisconsin Electric 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 and associated inventories and assumed the obligation to decommission the plant. Wisconsin Electric retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, Wisconsin Electric deferred the net gain on the sale of approximately $418 million as a regulatory liability and deposited those proceeds into a restricted cash account.
In connection with the sale, Wisconsin Electric also transferred $390 million of decommissioning funds to the buyer. Wisconsin Electric then liquidated the balance of the decommissioning trust assets and retained approximately $552 million, which was also placed into the restricted cash account. We are using the cash in the restricted cash account and the interest earned on the balance for the benefit of our customers and to pay certain taxes. Our regulators are directing the manner in which these proceeds will benefit customers. For further information on the 2008 rate case, see Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters in this report.
A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, Wisconsin Electric is 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 are paying a pre-determined price per MWh for energy delivered according to a schedule that is established in the agreement. Under the agreement, if our credit rating and the credit rating of Wisconsin Electric from either S&P or Moody's fall below investment grade, or if the holders of any indebtedness in excess of $100.0 million accelerate or have the right to accelerate the maturity of such indebtedness as a result of a default, we would need to provide collateral in the amount of $100.0 million (escalating at 3% per year commencing in 2024).
Used Nuclear Fuel Storage and Disposal: During Wisconsin Electric's ownership of Point Beach, Wisconsin Electric was authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed and extended by the NRC in December 2005.
Temporary storage alternatives at Point Beach are necessary until the DOE takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which Wisconsin Electric paid a total of $215.2 million into the Nuclear Waste Fund over the life of its ownership of Point Beach.
In August 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the DOE's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, Wisconsin Electric filed a complaint in November 2000 against the DOE in the Court of Federal Claims. In October 2004, the Court of Federal Claims granted Wisconsin Electric's motion for summary
judgment on liability. The Court held a trial during September and October 2007 to determine damages. We anticipate a decision during 2009. Wisconsin Electric incurred substantial damages prior to the sale of Point Beach and we are seeking recovery of our damages in this lawsuit, and we expect that any recoveries would be considered in setting future rates.
INDUSTRY RESTRUCTURING AND COMPETITION
Electric Utility Industry
The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which will affect the structure of the wholesale market. To this end, the MISO implemented bid-based markets, the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. The MISO Energy Markets commenced operation in April 2005 for energy distribution and in January 2009 for operating reserves. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail access might be implemented, if at all, in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. The Energy Policy Act, which included tax subsidies for electric utilities, amended federal energy laws and provided FERC with new oversight responsibilities, continues to significantly impact the electric utility industry. We continue to focus on infrastructure issues through our PTF growth strategy.
Restructuring in Wisconsin: Electric utility revenues in Wisconsin are regulated by the PSCW. Due to many factors, including relatively competitive electric rates charged by the state's electric utilities, the PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. These issues include:
Addition of new generating capacity in the state;
Modifications to the regulatory process to facilitate development of merchant generating plants;
Development of a regional independent electric transmission system operator;
Improvements to existing and addition of new electric transmission lines in the state; and
Addition of renewable generation.
The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.
Restructuring in Michigan: Our Michigan retail customers are allowed to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We have maintained our generation capacity and distribution assets and provide regulated service as we have in the past. We continue providing distribution and customer service functions regardless of the customer's power supplier.
Competition and customer switching to alternative suppliers in our service territories in Michigan has been limited. With the exception of two general inquiries, no alternate supplier activity has occurred in our service territories in Michigan. We believe that this lack of alternate supplier activity reflects our small market area in Michigan, our competitive regulated power supply prices and a general lack of interest in the Upper Peninsula of Michigan as a market for alternative electric suppliers.
Electric Transmission and Energy Markets
In MISO, base transmission costs are currently being paid by LSEs located in the service territories of each MISO transmission owner. In February 2008, FERC issued several orders confirming that the current transmission cost allocation methodology is just and reasonable and should continue in the future. These orders are subject to rehearings or appeals.
In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of RSG charges. FERC ordered MISO to resettle all affected transactions retroactive to the commencement of the energy market. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC's rulings have been challenged by MISO and numerous other market participants. MISO
commenced with the resettlement of the market in accordance with the orders in July 2007. The resettlement was completed in January 2008 and resulted in a net cost increase of $7.8 million to us. Several entities filed formal complaints with FERC on the assessment of these charges. We filed in support of these complaints.
In November 2007, FERC issued another RSG order related to the rehearing requests previously filed. This order provided a clarification that was contrary to how MISO implemented the last resettlement. Once again, several parties, including Wisconsin Electric, filed for rehearing and/or clarification with FERC.
In addition, FERC ruled on the formal complaints filed by other entities in August 2007. FERC ruled that the current RSG cost allocation methodology may be unjust and unreasonable and established a refund effective date of August 10, 2007. MISO was ordered to file a new cost allocation methodology by March 2008. MISO filed new tariff language which indicated the new cost allocation methodology cannot be applied retroactively. We extended our previous rehearing/clarification request to include the timeframe from the established refund date through March 2008. In September 2008, FERC set a paper hearing for the formal complaints filed in 2007. FERC ruled on the outstanding rehearing/clarification requests and formal complaints in November 2008. FERC's ruling orders the resettlements to begin from the date the MISO Energy Markets commenced in order to correct the RSG cost allocation methodology. Additionally, the order also set a new RSG cost allocation effective August 10, 2007. However, numerous entities filed rehearing requests in objection of these rulings. MISO requested a postponement of the resettlements until the matter is resolved. Based on our analysis of the FERC decision and MISO's proposed implementation of FERC's ruling, we estimate that there could be a refund to us of up to $15 million. Due to the uncertainty around the ultimate outcome of the RSG cost allocation, we have not reflected the potential impact of this potential resettlement on our financial statements as of December 31, 2008.
As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2008 through May 31, 2009. The resulting ARR valuation and the secured FTRs should adequately mitigate our transmission congestion risk for that period.
MISO has developed a market for two ancillary services, regulation reserves and contingency reserves. In February 2007, MISO filed tariff revisions to include ancillary services. The MISO ancillary services market began in January 2009. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market is expected to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market is also expected to enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.
Natural Gas Utility Industry
Restructuring in Wisconsin: The PSCW previously instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the gas distribution industry by the PSCW is presently on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.
ACCOUNTING DEVELOPMENTS
New Pronouncements: See Note B -- Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for information on new accounting pronouncements.
CRITICAL ACCOUNTING ESTIMATES
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments:
Regulatory Accounting: Our utility subsidiaries operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. Under SFAS 71, the actions of our regulators may allow us to defer costs that non-regulated entities would expense. The actions of our regulators may also require us to accrue liabilities that non-regulated companies would not. As of December 31, 2008, we had $1,343.6 million in regulatory assets and $1,395.3 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow SFAS 71. In this situation, continued deferral of certain regulatory asset and liability amounts on the utilities' books, as allowed under SFAS 71, may no longer be appropriate and the unamortized regulatory assets net of the regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. In addition, each quarter we perform a review of our regulatory assets and our regulatory environment and we evaluate whether we believe that it is probable that we will recover the regulatory assets in future rates. See Note C -- Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements for additional information.
Pension and OPEB: Our reported costs of providing non-contributory defined pension benefits (described in Note O -- Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
In accordance with SFAS 87 and SFAS 158, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.
The following chart reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant:
In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note O -- Benefits in the Notes to Consolidated Financial Statements). We account for these plans in accordance with SFAS 106. Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics
(age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the OPEB and post-retirement costs. Our OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns, as well as changes in general interest rates, may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, the regulators of our utility segment have adopted SFAS 106 for rate making purposes.
The following chart reflects OPEB plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant:
Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2008 of approximately $4.4 billion included accrued utility revenues of, $341.2 million as of December 31, 2008.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in this report for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.
ITEM 8
ITEM 8
WISCONSIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following operating segments:
Utility Energy Segment
-- Consisting of Wisconsin Electric, Wisconsin Gas and Edison Sault; engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and
Non-Utility Energy Segment
-- Consisting primarily of We Power; engaged principally in the design, development, construction and ownership of electric power generating facilities for long-term lease to Wisconsin Electric. Our Corporate and Other segment primarily includes Wispark, which develops and invests in real estate. We have eliminated all intercompany transactions and balances from the consolidated financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for services rendered but not billed.
Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules in Wisconsin allow us to request rate increases if fuel and purchased power costs exceed the band established by the PSCW. We are also required to reduce rates if fuel and purchased power costs fall below the band established by the PSCW.
Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.
For information regarding revenue recognition for PTF, see Note E.
Accounting for MISO Energy Transactions: MISO implemented the MISO Energy Markets on April 1, 2005. The MISO Energy Markets operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour.
Other Income and Deductions, Net: We recorded the following items in Other Income and Deductions, net for the years ended December 31:
Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.
We had the following property in service by segment as of December 31:
Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.7% in 2008, 2007 and 2006.
For assets other than our regulated assets, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets. Estimated useful lives for non-regulated assets are 3 to 40 years for furniture and equipment, 2 to 5 years for software and 30 to 40 years for buildings.
Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated ARO. W
e record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $693.5 million as of December 31, 2008 and $664.5 million as of December 31, 2007.
We recorded the following CWIP by segment at December 31:
Allowance For Funds Used During Construction - Regulated:
AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders'
capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC - Equity is recorded in Other Income and Deductions, net.
During 2008, Wisconsin Electric accrued AFUDC at a rate of 9.09% as authorized by the PSCW in its 2008 test year in docket 5-UR-103. Consistent with that order, Wisconsin Electric accrues AFUDC on 50% of all utility CWIP projects except its Oak Creek AQCS project which accrues AFUDC on 100% of CWIP. Wisconsin Electric's rates were set to provide a current return on CWIP that does not accrue AFUDC. During 2007 and 2006, Wisconsin Electric accrued AFUDC at a rate of 8.94%, as authorized by the PSCW.
During 2008, Wisconsin Gas accrued AFUDC at a rate of 10.80% on 50% of its CWIP as authorized by the PSCW in the 2008 test year in docket 5-UR-103. Wisconsin Gas' rates were set to provide a current return on CWIP that does not accrue AFUDC. During 2007 and 2006, Wisconsin Gas accrued AFUDC at a rate of 11.31%, as authorized by the PSCW.
Our regulated segment recorded the following AFUDC for the years ended December 31:
Capitalized Interest and Carrying Costs - Non-Regulated Energy:
As part of the construction of the power plants under our PTF program, we capitalize interest during construction in accordance with SFAS 34. Under the lease agreements associated with our PTF power plants, we are able to collect from utility customers the carrying costs associated with the construction of these power plants. We defer these carrying costs collected on our balance sheet and they will be amortized to revenue once the asset is placed in service over the individual lease term. For further information on the accounting for capitalized interest and deferred carrying costs associated with the construction of our PTF power plants, see Note E.
Earnings per Common Share: We compute basic earnings per common share by dividing our net income by the weighted average number of common shares outstanding. Diluted earnings per common share reflect the potential reduction in earnings per common share that could occur when potentially dilutive common shares are added to common shares outstanding.
We derive our potentially dilutive common shares by calculating the number of shares issuable relating to stock options utilizing the treasury stock method. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. Shares that are anti-dilutive are not included in the calculation.
Materials, Supplies and Inventories: Our inventory at December 31 consists of:
Substantially all fossil fuel, materials and supplies and natural gas in storage inventories are recorded using the weighted-average method of accounting.
Regulatory Accounting: Our utility energy segment accounts for its regulated operations in accordance with SFAS 71. This statement sets forth the application of GAAP to those companies whose rates are determined by an independent third-party regulator. The economic effects of regulation can result in regulated companies recording
costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets on the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. We defer all of our regulatory assets pursuant to specific orders or by a generic order issued by our primary regulator, the PSCW. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet. For further information, see Note C.
Asset Retirement Obligations: Consistent with SFAS 143 and FIN 47, we record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs under SFAS 143. For further information, see Note F.
Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS 133 which we report at fair value. For further information, see Note M.
Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
Restricted Cash: Cash proceeds that we received from the sale of Point Beach that are to be used for the benefit of our customers are recorded as restricted cash.
Margin Accounts: Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.
Goodwill and Intangible Assets: We account for goodwill and other intangible assets following SFAS 142. As of December 31, 2008 and 2007, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.
Under SFAS 142, goodwill and other intangibles with indefinite lives are not subject to amortization. However, goodwill and other intangibles are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. We assess the fair value of our SFAS 142 reporting unit by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test for the reporting unit as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2008 impairment test date for our reporting unit.
Impairment or Disposal of Long Lived Assets: We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2008, we had no assets classified as Held for Sale. Consistent with SFAS 144, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. For further information, see Note D.
Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2008 and 2007, we had a total ownership interest of approximately 26.2% and 26.9% in ATC. We are represented by one out of ten ATC board members, each of whom has one vote. Due to
the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note R.
Income Taxes: We follow the liability method in accounting for income taxes as prescribed by SFAS 109. SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. We have established a valuation allowance against certain deferred tax assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.
Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note H.
We recognize interest and penalties accrued related to unrecognized tax benefits in Income Taxes in our Consolidated Income Statements, as well as Regulatory Assets or Regulatory Liabilities in our Consolidated Balance Sheets.
We collect sales and use taxes from our customers and remit these taxes to governmental authorities. These taxes are recorded in our Consolidated Income Statements on a net basis.
Stock Options: Effective January 1, 2006, we adopted SFAS 123R, using the modified prospective method and use a binomial pricing model to estimate the fair value of stock options granted subsequent to that date. SFAS 123R also requires that we report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within "other paid in capital" in our Consolidated Statements of Common Equity. We do report excess tax benefits as a financing cash inflow. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than ten years from the grant date. Accordingly, no compensation expense was recognized in connection with option grants. For further discussion of this standard and the impacts to our Consolidated Financial Statements, see Note J.
The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted average assumptions:
B -- RECENT ACCOUNTING PRONOUNCEMENTS
Fair Value Measurements: In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities, defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We partially adopted the provisions of SFAS 157 effective January 1, 2008. We fully adopted the provisions of SFAS 157 effective January 1, 2009. The adoption of SFAS 157 did not have a significant financial impact on our consolidated financial statements. See Note N -- Fair Value Measurements for further information on SFAS 157.
Fair Value Option: In February 2007, the FASB issued SFAS 159. SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value and also establishes presentation and disclosure requirements. SFAS 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. We adopted the provisions of SFAS 159 effective January 1, 2008. The adoption of SFAS 159 did not have any financial impact on our consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities: In March 2008, the FASB issued SFAS 161. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We adopted the provisions of SFAS 161 effective January 1, 2009. The adoption of SFAS 161 did not have any financial impact on our consolidated financial statements.
Disclosures by Public Entities about Interests in Variable Interest Entities: In December 2008, the FASB issued FSP FIN 46(R)-8. FSP FIN 46(R)-8 amends FIN 46 to require public entities, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures regarding their involvement with variable interest entities. FSP FIN 46(R)-8 is effective for the first operating period (interim or annual) ending after December 15, 2008. We adopted the provisions of FSP FIN 46(R)-8 effective December 31, 2008. The adoption of FSP FIN 46(R)-8 did not have any financial impact on our consolidated financial statements. See Note G -- Variable Interest Entities for further information on FSP FIN 46(R)-8.
C -- REGULATORY ASSETS AND LIABILITIES
Our utility energy segment accounts for its regulated operations in accordance with SFAS 71.
Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed, or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our primary regulator. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2008 and 2007, we had approximately $28.2 million and $58.3 million, respectively, of net regulatory assets that were not earning a return.
In January 2008, the PSCW issued a rate order that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below. In addition, the rate order provided for the immediate recovery in January 2008 of $85.0 million related to deferred fuel costs and escrowed bad debt costs. The rate order also provided for the recovery over a six year period of the balance of the deferred fuel costs, escrowed bad debt costs and escrowed transmission costs. The order also specified that the deferred Point Beach gain would be passed on to customers over a three year period. Finally, the order eliminated the use of escrow accounting for transmission costs that are incurred after December 31, 2007.
Our regulatory assets and liabilities as of December 31 consist of:
We have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.
Our regulated subsidiaries record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues, see Note A.
Consistent with a generic order from, and past rate-making practices of, the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2008, we have recorded $56.8 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $23.9 million of deferrals for actual remediation costs incurred and a $32.9 million accrual for estimated future site remediation (see Note S). In addition, we have deferred $7.4 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We amortize the deferred costs actually incurred and insurance recoveries over five years in accordance with rate-making treatment.
As of December 31, 2008, we have $20.6 million of escrowed bad debt costs. The PSCW authorized escrow accounting for residential bad debt costs for both Wisconsin Gas and Wisconsin Electric whereby they defer actual bad debt write-offs that exceed amounts allowed in rates.
D -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS
Point Beach: Prior to September 28, 2007, Wisconsin Electric owned two 518 MW electric generating units (Unit 1 and Unit 2) at Point Beach in Two Rivers, Wisconsin. On September 28, 2007, Wisconsin Electric 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 and associated inventories and assumed the obligation to decommission the plant. Wisconsin Electric retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, Wisconsin Electric deferred the net gain on the sale of approximately $418 million as a regulatory liability and deposited those proceeds into a restricted cash account.
In connection with the sale, Wisconsin Electric also transferred $390 million of decommissioning funds to the buyer. Wisconsin Electric then liquidated the balance of the decommissioning trust assets and retained approximately $552 million of that cash. This cash was also placed into the restricted cash account. We are using the cash in the restricted cash account, and the interest earned on the balance, for the benefit of our customers and to pay certain taxes related to the liquidation of the qualified decommissioning trust. Our regulators are directing the manner in which these proceeds will benefit customers.
As of December 31, 2008, we have given approximately $347.1 million in bill credits to our Wisconsin and Michigan retail customers and issued a refund of approximately $62.5 million to wholesale customers in a one-time FERC-approved settlement. In addition, pursuant to the January 2008 PSCW rate order, during the first quarter of 2008, we used $85.0 million of restricted cash proceeds to recover $85.0 million of regulatory assets.
A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, Wisconsin Electric is 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 a predetermined price per MWh for energy delivered. Under the agreement, if our credit rating and the credit rating of Wisconsin Electric from either S&P or Moody's fall below investment grade, or if the holders of any indebtedness in excess of $100.0 million accelerate or have the right to accelerate the maturity of such indebtedness as a result of a default, we would need to provide collateral in the amount of $100.0 million (escalating at 3% per year commencing in 2024). For further information regarding our former nuclear operations, see Note I.
Minergy Neenah, LLC: Effective September 27, 2006, we sold 100% of the membership interest in Minergy Neenah, LLC to a third party. The primary assets of Minergy Neenah, LLC were a Glass Aggregate plant and related operating contracts. The largest source of revenue for Minergy Neenah, LLC was a long-term steam contract with an adjacent paper mill. The mill was permanently closed as of June 30, 2006. Pursuant to the steam contract, the mill owner paid Minergy Neenah, LLC a contract termination payment. In the third quarter of 2006, we received gross proceeds from the sale of the plant and the contract termination totaling $12.2 million and we recorded a net loss of $0.4 million that is included in Income from Discontinued Operations, Net of tax.
We have recorded the operating results of Minergy Neenah, LLC as Income from Discontinued Operations, Net of Tax in the accompanying Consolidated Income Statements for the year ended December 31, 2006.
The total effect on operating revenues for Minergy Neenah, LLC was $14.3 million in 2006. The income before taxes was $2.4 million for the same year. The gain on discontinued operations for 2008, 2007 and 2006 was not material.
E -- ACCOUNTING AND REPORTING FOR pOWER THE FUTURE GENERATING UNITS
Background: As part of our PTF strategy, our non-utility subsidiary, We Power, is building four new generating units (PWGS 1 and 2 and OC 1 and 2) that will be leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW, our primary regulator. The leases are designed to recover the capital costs of the plant including a return. PWGS 1 was placed in service in July 2005 and PWGS 2 was placed in service in May 2008.
The construction of the Oak Creek expansion includes projects that will benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system. The costs associated with these projects are included in the OC 1 captions below. In November 2007, the coal handling system for Oak Creek was placed in service, and the water intake system was placed in service in January 2009. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.
During Construction: Under the terms of each lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for the PTF units. Our pre-tax cost of capital
is approximately 14%. The carrying costs that we collect in rates are recorded as deferred revenue and will be amortized to revenue over the term of the lease once the respective unit is placed in service. During the construction of our PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest of approximately 6%. Capitalized interest is included in the total cost of the PTF units.
Cash Flows: The following table identifies key pre-tax cash outflows and inflows for the year ended December 31 related to the construction of our PTF units as compared to Wisconsin Energy overall:
Balance Sheet: As noted above, we collect in current rates carrying costs that are calculated based on the cash expenditures included in CWIP multiplied by our pre-tax cost of capital. The carrying costs are recorded as deferred revenue and included in long-term liabilities. Our total CWIP balance includes cash expenditures, capitalized interest and accruals. The following table identifies key amounts related to our PTF units that are recorded on our balance sheet as of December 31, 2008 and 2007:
Income Statement:
Once the PTF units are placed in service, we expect to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return on the investment. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs are recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first five years of the leases. The leases established a set return on equity component of 12.7% after tax. The interest component of the return is determined up to 180 days prior to the date that the units are placed in service.
We recognize revenues related to the lease payments that are included in our rates. In addition, our revenues include the amortization of the deferred revenues that reflect the carrying costs that are collected during construction. The deferred revenue is amortized on a straight-line basis over the lease term. We depreciate the units on a straight-line basis over their expected service life.
In July 2005, PWGS 1 was placed in service. This asset had a cost of approximately $364.3 million, which included approximately $31.1 million of capitalized interest. The asset is being depreciated over its estimated useful life of approximately 37 years. The cost of the plant, plus a return on the investment, is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $48 million.
In November 2007, the coal handling system for Oak Creek was placed into service. As of December 31, 2008, this asset had a cost of approximately $199.1 million, which included approximately $9.6 million of capitalized interest. This asset is being depreciated over its estimated useful life of approximately 40 years. The cost of the system, plus a return on the investment, is expected to be recovered through Wisconsin Electric's rates over a 32 year period at an annual amount of approximately $24 million.
In May 2008, PWGS 2 was placed in service. As of December 31, 2008, this asset had a cost of approximately $366.3 million, which included approximately $34.0 million of capitalized interest. The asset is being depreciated over its estimated useful life of approximately 37 years. The cost of the plant, plus a return on the investment, is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $49 million.
F -- ASSET RETIREMENT OBLIGATIONS
The following table presents the change in our AROs during 2008:
Our AROs were significantly reduced during 2007 due to the sale of Point Beach. Upon closing of the sale, the buyer assumed the liability to decommission the plant, including the ARO spent fuel and the obligation to return the site to greenfield status.
G -- VARIABLE INTEREST ENTITIES
Under FIN 46 and FIN 46R, the primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. In December 2008, the FASB issued FSP FIN 46(R)-8 requiring additional disclosures by sponsors, significant interest holders in variable interest entities and potential variable interest entities.
We assess our relationships to potential variable interest entities such as our coal suppliers, natural gas suppliers, coal and gas transporters, and other counterparties in power purchase agreements and joint ventures as prescribed by FIN 46R. We consider the potential that our contracts or other arrangements provide subordinated financial support,
the potential for us to absorb losses or rights to residual returns of the entity, the ability to directly or indirectly make decisions about the entities' activities and other factors.
We have identified two tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of these two variable interest entities as defined by FIN 46. The requested information required to make this determination has not been supplied. As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and the other contract as an operating lease. A similar power purchase agreement expired during the second quarter of 2008. We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. We have approximately $471.5 million of required payments over the remaining terms of these two agreements, which expire over the next 14 years. We believe the required payments or any replacement power purchased will continue to be recoverable in rates. Total capacity and minimum lease payments under these contracts in 2008, 2007 and 2006 were $66.4 million, $70.4 million and $68.9 million, respectively.
H -- INCOME TAXES
The following table is a summary of income tax expense for each of the years ended December 31:
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:
The components of SFAS 109 deferred income taxes classified as net current liabilities and net long-term liabilities at December 31 are as follows:
Consistent with ratemaking treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.
As of December 31, 2008 and 2007, we had recorded $3.2 million and $3.3 million, respectively, of valuation allowances primarily related to the uncertainty of our ability to benefit from state loss carryforwards in the future. Portions of these state loss carryforwards began expiring in 2008.
We adopted the provisions of FIN 48 on January 1, 2007. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
The amount of unrecognized tax benefits as of December 31, 2008 and 2007, excludes FIN 48 related deferred tax assets of $13.2 million and $8.5 million, respectively. As of December 31, 2008 and 2007, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $9.3 million and $9.2 million, respectively.
We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2008 and 2007, we recognized approximately $3.3 million and $3.0 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2008 and 2007, we recognized no penalties in the Consolidated Income Statements. We had approximately $9.0 million and $6.2 million of interest and $0.9 million and $1.0 million of penalties accrued on the Consolidated Balance Sheets as of December 31, 2008 and 2007, respectively.
We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next twelve months.
Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2004 through 2008 are subject to Federal and Wisconsin examination.
I -- NUCLEAR OPERATIONS
The sale of Point Beach was completed on September 28, 2007. The discussion below reflects decommissioning and nuclear operations through September 28, 2007.
Nuclear Decommissioning: We recorded decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs were accrued over the expected service lives of the nuclear generating units and were included in electric rates. The decommissioning funding was $11.2 million through September 2007 and $17.6 million for the year ended 2006. We liquidated our decommissioning trust assets as part of the sale of Point Beach. We had no investments in our Nuclear Decommissioning Trusts as of December 31, 2008 and 2007.
Our investments in the trusts were recorded at fair value and we were allowed regulatory treatment for the fair value adjustment. Realized gains and losses for the years ended December 31, 2008 and 2007 were as follows:
Total gains and total losses by security type for the years ended December 31, 2008 and 2007 were as follows:
Decontamination and Decommissioning Fund: The Energy Policy Act of 1992 established a D&D Fund for the DOE's nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. In October 2006, a final payment was made to the DOE. As a result, a liability no longer exists for this fund. The deferred regulatory asset was amortized to nuclear fuel expense and included in utility rates through September 2007.
J -- Common equity
As of December 31, 2008 and 2007, we had 325,000,000 shares of common stock authorized under our charter, of which 116,917,790 and 116,943,072 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.
Share-Based Compensation Plans:
We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in common stock, cash or a combination thereof. Effective January 1, 2006, we adopted SFAS 123R using the modified prospective method. We utilize the straight-line attribution method for recognizing share-based compensation expense under SFAS 123R. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding stock options during the period.
The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:
Stock Options: The exercise price of a stock option under the plan is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. Option grants consist of non-qualified stock options and vest on a cliff-basis after a three year period. Options expire no later than ten years from the date of grant. For further information regarding stock-based compensation and the valuation of our stock options, see Note A.
Stock options to purchase 12,000, 1,366,625 and 1,357,365 shares of common stock at $42.56, $47.76 and $48.04 per share, respectively, were outstanding as of December 31, 2008, but were not included in the computation of diluted earnings per share, because they were anti-dilutive.
The following is a summary of our stock options issued through December 31, 2008:
We expect that substantially all of the outstanding options as of December 31, 2008 will be exercised.
In January 2009, the Compensation Committee awarded 1,216,625 non-qualified stock options with an exercise price of $42.22 to our officers and key executives under its normal schedule of awarding long-term incentive compensation.
The intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 was $10.2 million, $30.0 million and $21.1 million, respectively. Cash received from options exercised during the years ended December 31, 2008, 2007 and 2006 was $11.6 million, $36.1 million and $26.8 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $3.5 million, $11.2 million and $8.4 million, respectively.
The following table summarizes information about stock options outstanding as of December 31, 2008:
The following table summarizes information about our non-vested options through December 31, 2008:
As of December 31, 2008, total compensation costs related to non-vested stock options not yet recognized was approximately $9.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.
Restricted Shares: The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2008:
Recipients of the restricted shares have the right to vote the shares and receive dividends. Forfeiture provisions on restricted stock generally expire 10 years after the award date subject to an accelerated expiration schedule for some of the shares based on the achievement of certain financial performance goals.
We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals. The intrinsic value of restricted stock vesting was $2.1 million, $2.9 million and $0.9 million for the years ended December 31, 2008, 2007, and 2006, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.5 million, $1.1 million and $0.5 million, respectively.
As of December 31, 2008, total compensation cost related to restricted stock not yet recognized was approximately $1.6 million, which is expected to be recognized over the next 37 months on a weighted-average basis.
Performance Units: In January 2009, 2008 and 2007 the Compensation Committee granted 333,720, 133,855 and 136,905 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of our stock over a three year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. All grants are settled in cash. We are accruing compensation costs over the three year performance period based on our estimate of the final expected value of the award. In July 2006, the Compensation Committee amended the terms of performance shares granted in 2004 to allow the recipients to receive cash or common stock upon settlement. During the third quarter of 2006, we transferred $6.3 million from Common Equity to Other Liabilities to reflect participant elections to take cash under this amendment. Performance units earned as of December 31, 2008, 2007 and 2006 had a total intrinsic value of $8.4 million, $5.2 million and $7.2 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2009, 2008 and 2007. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $3.1 million, $1.8 million and $2.1 million,
respectively. As of December 31, 2008, total compensation cost related to performance units not yet recognized was approximately $6.3 million, which is expected to be recognized over the next 19 months on a weighted-average basis.
Common Stock Activity: We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2008, 2007 or 2006.
During 2008, 2007 and 2006, our plan agents purchased 0.5 million shares at a cost of $23.0 million, 1.4 million shares at a cost of $67.8 million and 1.1 million shares at a cost of $48.0 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2008, 2007 and 2006, we received proceeds of $11.6 million, $36.1 million and $26.8 million, respectively, related to the exercise of stock options.
Restrictions: Wisconsin Energy's ability to pay common dividends depends on the availability of funds received from our principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2008, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $431.6 million of dividends. In the future, as the new PTF plants continue to be placed in service, we expect that We Power will also provide funds for Wisconsin Energy to pay dividends.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.
The January 2008 rate order requires Wisconsin Electric and Wisconsin Gas to maintain capital structures as set forth by the PSCW. These capital structures differ from GAAP as they reflect regulatory adjustments. Wisconsin Electric is required to maintain a common equity ratio range of between 48.5% and 53.5% and Wisconsin Gas is to maintain a capital structure which has a common equity range of between 45.0% and 50.0%. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.
Wisconsin Electric may not pay common dividends to Wisconsin Energy under Wisconsin Electric's Restated Articles of Incorporation if any dividends on Wisconsin Electric's outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric's 3.60% Serial Preferred Stock, Wisconsin Electric's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if Wisconsin Electric's common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.
We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.
As of December 31, 2008, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $2.8 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2008.
See Note L for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
K -- LONG-TERM DEBT
Debentures and Notes: As of December 31, 2008, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:
We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.
During 2008, our subsidiaries issued $706 million of senior notes, including $550 million of notes under an existing $800 million shelf registration statement filed by Wisconsin Electric with the SEC in August 2007. Of the total amount issued during 2008, $156 million was issued by PWGS and is secured by a collateral assignment of the leases between PWGS and Wisconsin Electric related to PWGS 2. The net proceeds were used to repay short-term debt.
In addition, in December 2008, Wisconsin Energy borrowed $260 million under an 18- month credit facility and used such amount to repay short-term debt. Similar to Wisconsin Energy's bank back-up credit facility, this agreement requires us to maintain, subject to certain exclusions, a minimum funded debt to capitalization ratio of less than 70%, and also contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default. In addition, Wisconsin Energy must ensure that certain of its subsidiaries comply with many of the covenants contained therein. As of December 31, 2008, Wisconsin Energy was in compliance with all covenants under the credit agreement.
Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. The bonds previously bore interest at an "auction rate". In March 2008, because of substantial disruptions in the auction rate bond market, Wisconsin Electric purchased (in lieu of redemption) these bonds at a purchase price of par plus accrued interest to the date of purchase. In August 2008, Wisconsin Electric converted the interest rate determination method for the bonds to a weekly rate and they were remarketed to third parties. Letters of credit from Wells Fargo Bank, National Association now provide credit and liquidity support for the remarketed bonds. Prior to the remarketing, Wisconsin Electric held the bonds and they remained outstanding; however, because they were held by Wisconsin Electric, they were not reflected in our consolidated long-term debt.
During December 2008, Wisconsin Energy retired $350.8 million of notes through the issuance of short-term debt.
In May 2007, we issued $500 million of Junior Notes. Due to certain features of the Junior Notes, rating agencies consider them to be hybrid instruments with a combination of debt and equity characteristics. These securities were issued under a shelf registration statement filed with the SEC in May 2007 for an unlimited number of debt securities, which became effective upon filing. The Junior Notes bear interest at 6.25% per year until May 15, 2017. Beginning May 15, 2017, the Junior Notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.1125%, reset quarterly. The proceeds from this issuance were used to repay short-term debt incurred to both fund PTF and for other working capital purposes.
In connection with the issuance of the Junior Notes, we executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been initially designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to
certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
During December 2007, Wisconsin Electric retired $250 million of notes through the issuance of short-term debt.
During November 2006, Wisconsin Electric issued $300 million of notes due December 1, 2036 under an existing shelf registration statement filed by Wisconsin Electric with the SEC.
Obligations Under Capital Leases: In 1997, Wisconsin Electric entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.
We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $28.1 million, $27.1 million and $26.1 million in minimum lease payments during 2008, 2007 and 2006, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related -- capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million during 2009, at which time the regulatory asset will be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $154.1 million at December 31, 2008 and will decrease to zero over the remaining life of the contract.
Wisconsin Electric had a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust, which was treated as a capital lease. Under this arrangement, Wisconsin Electric leased and amortized nuclear fuel to fuel expense as power was generated. In connection with the sale of Point Beach, the nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust was dissolved in September 2007. Wisconsin Electric terminated the lease and paid off all of Wisconsin Electric Fuel Trust's outstanding commercial paper, aggregating $76.2 million.
Following is a summary of our capitalized leased facilities as of December 31:
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2008 are as follows:
L -- SHORT-TERM DEBT
Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:
The following information relates to Short-Term Debt for the years ended December 31:
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into various bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.
An affiliate of Lehman Brothers Holdings, which filed for bankruptcy in September 2008, provided approximately $80 million of commitments under our bank back-up facilities on a consolidated basis. As of December 31, 2008, excluding Lehman's commitments, we had approximately $1.6 billion of available undrawn lines under our bank back-up credit facilities on a consolidated basis. Our bank back-up credit facilities expire in March 2011 and April 2011, but may be renewed for two one-year extensions, subject to lender approval.
The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and
warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with many of the covenants contained therein.
As of December 31, 2008, we were in compliance with all covenants.
M -- DERIVATIVE INSTRUMENTS
We follow SFAS 133, as amended by SFAS 149, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of December 31, 2008, we recognized $84.4 million in regulatory assets and $11.9 million in regulatory liabilities related to derivatives in comparison to $24.3 million in regulatory assets and $14.5 million in regulatory liabilities as of December 31, 2007.
For the years ended December 31, 2008, 2007 and 2006, we reclassified $0.4 million, $0.3 million and $0.4 million respectively, in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest Expense. We estimate that during the next 12 months, $0.4 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.
N -- FAIR VALUE MEASUREMENTS
We adopted SFAS 157 as of January 1, 2008, which among other things, requires enhanced disclosures about assets and liabilities that are measured and reported at fair value. SFAS 157 establishes a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.
As defined in SFAS 157, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy established under SFAS 157 gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).
Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories:
Level 1 -- Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.
Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as OTC forwards and options.
Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to SFAS 157 and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.
The following table summarizes our financial assets and liabilities by level within the fair value hierarchy as of December 31, 2008:
Cash Equivalents consist of certificates of deposit and money market funds. Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.
The following table summarizes the fair value of derivatives classified as Level 3 in the fair value hierarchy:
Derivative instruments reflected in Level 3 of the hierarchy include FTRs allocated by MISO that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet in accordance with SFAS 71. See Note M -- Derivative Instruments, for further information on the offset to regulatory assets and liabilities.
The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:
The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.
O -- BENEFITS
Pensions and Other Post-retirement Benefits: We have defined benefit pension plans that cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.
We also have OPEB plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees.
We follow SFAS 158 and use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.
The following table presents details about our pension and OPEB plans:
The accumulated benefit obligation for all defined benefit plans was $1,117.2 million and $1,147.8 million as of December 31, 2008 and 2007, respectively.
The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:
The following table shows the estimated amounts that will be amortized as a component of net periodic benefit costs during 2009:
Information for pension plans with an accumulated benefit obligation in excess of the fair value of assets as of December 31 is as follows:
The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:
The expected long-term rate of return on plan assets was 8.5% in 2008, 2007 and 2006. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the asset categories utilized in the pension fund.
A one-percentage-point change in assumed health care cost trend rates would have the following effects:
We use various Employees' Benefit Trusts to fund a major portion of OPEB. The majority of the trusts' assets are mutual funds or commingled indexed funds.
Plan Assets: In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2008 and 2007, and our target allocation for 2009, by asset category, are as follows:
Our OPEB plans asset allocation at December 31, 2008 and 2007, and our target allocation for 2009, by asset category, are as follows:
Our common stock is not included in equity securities.
The target asset allocations were established by our Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. The asset allocations are monitored by the Investment Trust Policy Committee.
Cash Flows:
In January 2009, we contributed $270 million to our qualified pension plan and approximately $19 million to our OPEB plan. We contributed $38.6 million, $20.0 million and $55.4 million to our qualified pension plan during 2008, 2007 and 2006, respectively.
The entire contribution to the OPEB plans during 2008 was discretionary as the plans are not subject to any minimum regulatory funding requirements.
The following table identifies our expected benefit payments over the next 10 years:
Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and or after-tax income in accordance with plan-specified guidelines. Under these plans we expensed matching contributions of $14.8 million, $12.1 million and $10.4 million during 2008, 2007 and 2006, respectively.
P -- GUARANTEES
We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2008, we had the following guarantees:
A non-utility energy segment guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with The United Illuminating Company. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.
Other guarantees support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.
Wisconsin Electric is subject to the potential retrospective premiums that could be assessed under its insurance program.
Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, our subsidiary would be responsible for the obligations.
Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $18.6 million as of December 31, 2008.
Q -- SEGMENT REPORTING
Our reportable operating segments at December 31, 2008 include a utility energy segment and a non-utility energy segment. We have organized our reportable operating segments based in part upon the regulatory environment in which our utility subsidiaries operate. In addition, the segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.
Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.
Summarized financial information concerning our reportable operating segments for each of the three years ended December 31, 2008 is shown in the following table. The segment information below includes income from discontinued operations as a result of sales of non-utility businesses announced or completed in 2006:
(a)
Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, non-utility investment in renewable energy and recycling technologies by Minergy as well as interest on corporate debt. A gain on the sale of the manufacturing segment in 2004 resulted in a 2006 tax adjustment and is reflected in Corporate and Other. In 2006, we sold Minergy Neenah and the gain from the sale is included in Income from Discontinued Operations, Net. Certain overheads reported for Minergy Neenah continue to exist following the sale and are reported in continuing operations, while certain other costs are directly attributable to the discontinued operations.
(b)
An elimination for intersegment revenues of $119.0 million, $70.3 million and $64.1 million is included in Operating Revenues for 2008, 2007 and 2006, respectively. This elimination is primarily between We Power and Wisconsin Electric.
(c)
An elimination of $794.0 million and $465.4 million is included in Total Assets at December 31, 2008 and 2007, respectively, for the PWGS 1, PWGS 2 and Oak Creek coal handling leases between We Power and Wisconsin Electric.
R -- RELATED PARTIES
We receive and/or provide certain services to other associated companies in which we have an equity investment.
American Transmission Company LLC: As of December 31, 2008, we have a 26.2% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction, including generating units being constructed as part of our PTF strategy. ATC will reimburse us for these costs when new generation is placed into service. As of December 31, 2008 and 2007, we had a receivable of $32.6 million and $35.8 million, respectively, for these items.
Nuclear Management Company: Prior to the Point Beach sale, we had a partial ownership in NMC. NMC held the operating licenses of Point Beach. Upon the sale of Point Beach, NMC transferred the operating licenses to the buyer and our relationship with NMC was terminated.
We provided and received services from the following associated companies during 2008, 2007 and 2006:
As of December 31, 2008 and 2007, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:
S -- COMMITMENTS AND CONTINGENCIES
Capital Expenditures: We have made certain commitments in connection with 2009 capital expenditures. During 2009, we estimate that total capital expenditures will be approximately $875 million.
Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases including leases for vehicles and coal cars.
Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:
Divested Assets: Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets.
Pursuant to the terms of the sale agreement for Minergy Neenah, we have agreed to customary indemnification provisions related to post-closing obligations and other matters. Our maximum aggregate exposure under the indemnification provisions is $0.3 million.
Pursuant to the terms of the sales agreement for the manufacturing business, Wisconsin Energy agreed to customary indemnification provisions related to certain environmental, asbestos, and product liability matters. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals of the fair value of Wisconsin Gas assets and applicable tax laws. Any changes in the estimates of taxes and indemnification matters will be recorded as an adjustment to the gain on sale and reported in discontinued operations in the period the adjustment is determined. We have established reserves related to these customary indemnification and tax matters.
Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.
We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-ash disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal ash disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the WDNR in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
Manufactured Gas Plant Sites: We have identified several sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $25 to $50 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2008, we have established reserves of $32.9 million related to future remediation costs.
The PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.
Ash Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion by-products. However, these coal-ash by-products have been, and to a small degree continue to be, disposed of in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where Wisconsin Electric has become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are recovered
under the fuel clause for Wisconsin Electric and are expensed as incurred. During 2008, 2007 and 2006, Wisconsin Electric incurred $1.3 million, $0.8 million and $0.5 million respectively, in coal-ash remediation expenses. As of December 31, 2008, we have no reserves established related to ash landfill sites.
EPA - Consent Decree: In April 2003, Wisconsin Electric and the EPA announced that a Consent Decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. In July 2003, the Consent Decree was amended to include the state of Michigan. Under the Consent Decree, Wisconsin Electric agreed to significantly reduce its air emissions from its coal-fired generating facilities. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment and retiring certain older units. Through December 31, 2008, we have spent approximately $506.7 million associated with implementing the Consent Decree. The total cost of implementing this agreement is estimated to be $1.2 billion through the year 2013. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007.
Oak Creek: In July 2008, Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, notified us in a letter that it forecasts the in-service date of unit 1 to be delayed three months beyond the guaranteed contract date of September 29, 2009. Bechtel also advised us in the letter that it forecasts the in-service date of unit 2 to be one month earlier than the guaranteed contract date of September 29, 2010.
According to the letter, reasons for the delay of unit 1 include severe winter weather experienced during the winters of 2006-2007 and 2007-2008, exacerbated by severe rain storms in April and June of 2008, changes in local labor conditions from those anticipated by Bechtel, the cumulative impact of a large number of change orders and delay in receiving FNTP in 2005 as a result of the court challenges by certain opposition groups to the CPCN for the Oak Creek expansion. Bechtel advised that they expected to submit a claim for cost and schedule relief associated with these issues by the end of 2008.
Based on Bechtel's earlier communications, we notified Bechtel on September 29, 2008, that we were invoking the formal dispute resolution process provided in the contract in order to resolve certain issues related to the rights of the parties under the contract.
We received Bechtel's claims for schedule and cost relief on December 22, 2008. Bechtel continues to target an in-service date for unit 1 three months beyond the guaranteed contract date of September 29, 2009, and an in-service date for unit 2 one month earlier than the guaranteed contract date of September 29, 2010. However, Bechtel does request schedule relief that would result in six months of relief from liquidated damages beyond the guaranteed contract date for unit 1 and three months of relief from liquidated damages beyond the guaranteed contract date for unit 2.
Bechtel's first claim is based on the alleged impact of severe weather and certain labor-related matters. Bechtel is requesting approximately $413 million in costs related to changed weather and labor conditions. Although Bechtel has reserved the right to request future additional costs and schedule relief, this amount includes $45 million of projected future costs in addition to those already incurred.
The weather events for which Bechtel seeks cost and schedule relief are (i) extreme winds from September 2006 through April 2007, (ii) snowstorms from December 2007 through April 2008, and (iii) rain storms in June 2008. Bechtel contends that these weather events constituted events of force majeure. We will conduct a detailed analysis of Bechtel's force majeure claim to determine whether Bechtel is entitled to any schedule relief as a result of these weather events. We believe Bechtel's request for cost relief related to its claim of force majeure is without merit. Bechtel also claims that these same weather events constituted changed local conditions that it could not have reasonably foreseen and that caused it to incur additional costs. We believe that the claim for additional costs and schedule relief based on a change in local conditions is without merit.
The alleged changes in labor conditions for which Bechtel seeks cost and schedule relief are (i) a significant shortage in the availability of craft labor, (ii) significant increases in competing projects, (iii) the overtime and per diems allegedly necessary to attract labor, and (iv) alleged restrictions that our Project Labor Agreement placed on Bechtel's ability to attract and retain craft labor. Bechtel describes these as changed local conditions for which it believes we should bear the risk. Under the terms of the contract, we agreed to accept labor-related risk only as to
wage escalation in excess of 4% annually as measured by published wage bulletins. Therefore, we believe that this claim is without merit.
Bechtel's second claim of approximately $72 million seeks cost and schedule relief for the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the FNTP in July 2005 as follows: (i) the delay in issuing certain limited notices to proceed; (ii) the delay in issuing the FNTP until the final resolution of litigation brought by certain opposition groups that challenged the CPCN for the Oak Creek expansion; (iii) the imposition of additional limits to third party cancellation charges which allegedly restricted Bechtel's ability to issue purchase orders; (iv) the reduction of the pre-FNTP monthly payments below the amounts required by the contract; and (v) the request by ERS to perform design studies and issue design changes during the pre-FNTP period. We believe that this claim is without merit. We believe Bechtel was fully compensated for any and all impacts of the delayed start as indicated in certain change orders entered into between ERS and Bechtel prior to the start of construction of the Oak Creek expansion. Further, we do not believe that the contract provides for relief based upon the cumulative impact of change orders.
We continue to believe that the only circumstances and events for which we currently retain price adjustment risk under the contract are force majeure, wage escalation in excess of 4% annually as measured by published wage bulletins, delays caused by us, changes in scope or performance requested by us and unforeseen sub-surface ground conditions.
We are currently in the mediation phase with respect to determining the parties' rights under the contract and Bechtel's claims. We are currently unable to predict the ultimate outcome of the claims.
T -- SUPPLEMENTAL CASH FLOW INFORMATION
During the twelve months ended December 31, 2008, we paid $144.2 million in interest, net of amounts capitalized, and $2.4 million in income taxes, net of refunds. During the twelve months ended December 31, 2007, we paid $191.4 million in interest, net of amounts capitalized, and $291.6 million in income taxes, net of refunds. During the twelve months ended December 31, 2006, we paid $183.4 million in interest, net of amounts capitalized, and $154.2 million in income taxes, net of refunds.
As of December 31, 2008, 2007 and 2006, the amount of accounts payable related to capital expenditures was $45.1 million, $132.6 million and $62.9 million, respectively.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Energy Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2009 expressed an unqualified opinion on the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP Milwaukee, Wisconsin
February 25, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the internal control over financial reporting of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2008 of the Company and our report dated February 25, 2009 expressed an unqualified opinion on those financial statements and financial statement schedules.
DELOITTE & TOUCHE LLP Milwaukee, Wisconsin
February 25, 2009
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting was effective as of December 31, 2008.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on the effectiveness of Wisconsin Energy Corporation's and its subsidiaries' internal control over financial reporting as of December 31, 2008. Deloitte & Touche LLP's report is included in this report.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
The information under "Proposal 1: Election of Directors - Terms Expiring in 2010", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance - Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to the Corporate Governance Committee?", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Are all the members of the audit committee financially literate and does the committee have an audit committee financial expert?" and "Committees of the Board of Directors - Audit and Oversight" in our definitive Proxy Statement on Schedule 14A to be filed with the SEC for our Annual Meeting of Stockholders to be held May 7, 2009 (the "2009 Annual Meeting Proxy Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.
We have adopted a written code of ethics, referred to as our Code of Business Conduct, that all of our directors, executive officers and employees, including the principal executive officer, principal financial officer and principal accounting officer, must comply with. We have posted our Code of Business Conduct on our website, www.wisconsinenergy.com. We have not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on our website or in a current report on Form 8-K.
Our website, www.wisconsinenergy.com, also contains our Corporate Governance Guidelines and the charters of our Audit and Oversight, Corporate Governance and Compensation Committees.
Our Code of Business Conduct, Corporate Governance Guidelines and committee charters are also available without charge to any stockholder of record or beneficial owner of our common stock by writing to the corporate secretary, Susan H. Martin, at our principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information under "Compensation, Discussion and Analysis", "Executive Officers' Compensation", "Director Compensation", "Committees of the Board of Directors - Compensation" and "Compensation Committee Report" in the 2009 Annual Meeting Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The security ownership information called for by Item 12 of Form 10-K is incorporated herein by reference to this information included under "WEC Common Stock Ownership" in the 2009 Annual Meeting Proxy Statement.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information about our equity compensation plans as of December 31, 2008:
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information under "Corporate Governance - Frequently Asked Questions: Who are the independent directors?", "Corporate Governance - Frequently Asked Questions: What are the Board's standards of independence" and "Certain Relationships and Related Transactions" in the 2009 Annual Meeting Proxy Statement is incorporated herein by reference. A full description of the guidelines our Board uses to determine director independence is located in Appendix A of our Corporate Governance Guidelines, which can be found on our website, www.wisconsinenergy.com.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2009 Annual Meeting Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1.
FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT
Consolidated Income Statements for the three years ended December 31, 2008.
Consolidated Balance Sheets at December 31, 2008 and 2007.
Consolidated Statements of Cash Flows for the three years ended December 31, 2008.
Consolidated Statements of Common Equity for the three years ended December 31, 2008.
Consolidated Statements of Capitalization at December 31, 2008 and 2007.
Notes to Consolidated Financial Statements.
Reports of Independent Registered Public Accounting Firm.
2.
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
Schedule I Condensed Parent Company Financial Statements, including Income Statements and Cash Flows for the three years ended December 31, 2008 and Balance Sheets at December 31, 2008 and 2007.
Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2008.
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.
EXHIBITS AND EXHIBIT INDEX
See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.
WISCONSIN ENERGY CORPORATION
INCOME STATEMENTS
(Parent Company Only)
SCHEDULE I -- CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS
WISCONSIN ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
BALANCE SHEETS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
1. For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.
2. Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2008, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $431.6 million of dividends and distributions. In the future, as the new PTF plants continue to be placed in service, it is expected that We Power will also be a source for distributions to Wisconsin Energy.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's principal utility subsidiaries to transfer funds to the Parent Company in the form of cash dividends or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.
Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.
3. As of December 31, 2008, the maturities of the Parent Company long-term debt outstanding were as follows:
Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.
In December 2008, Wisconsin Energy borrowed $260 million under an 18-month credit agreement and used such amount to repay short-term debt. Similar to Wisconsin Energy's bank back-up credit facility, this agreement requires Wisconsin Energy to maintain, subject to certain exclusions, a minimum funded debt to capitalization ratio of less than 70%, and also contains customary covenants, including certain limitations on our ability to sell assets. The credit agreement also contains customary events of default. In addition, Wisconsin Energy must ensure that certain of its subsidiaries comply with many of the covenants contained therein. As of December 31, 2008, Wisconsin Energy was in compliance with all covenants under the credit agreement.
During 2008, Wisconsin Energy retired $300 million of notes through the issuance of short-term debt.
In May 2007, Wisconsin Energy issued $500 million of Junior Notes. Due to certain features of the Junior Notes, rating agencies consider them to be hybrid instruments with a combination of debt and equity characteristics. These securities were issued under a shelf registration statement filed with the SEC in May 2007 for an unlimited number of debt securities, which became effective upon filing. The Junior Notes bear interest at 6.25% per year until
May 15, 2017. Beginning May 15, 2017, the Junior Notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.1125%, reset quarterly. The proceeds from this issuance were used to repay short-term debt incurred to both fund PTF and for other working capital purposes.
In connection with the issuance of the Junior Notes, Wisconsin Energy executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Wisconsin Energy's 6.20% Senior Notes due April 1, 2033 have been initially designated as the covered debt under the RCC. The RCC provides that Wisconsin Energy may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Wisconsin Energy has entered into a bank back-up credit facility to maintain short-term liquidity which, among other terms, requires Wisconsin Energy to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.
Wisconsin Energy's bank back-up credit facility contains customary covenants, including certain limitations on its ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with many of the covenants contained therein.
As of December 31, 2008, Wisconsin Energy was in compliance with all covenants.
4. Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2008, Wisconsin Energy had the following guarantees:
Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and interconnection agreements.
The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.
Wisconsin Energy's guarantees in support of our non-utility Energy segment guaranty performance and payment obligations of We Power and Wisvest. A guarantee in support of Wisvest-Connecticut which we sold in December 2002 to PSEG provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement with the United Illuminating Company. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that Wisconsin Energy is required to perform under the guarantee. Guarantees also support obligations to third parties under the agreement with PSEG for the sale of Wisvest-Connecticut and post-closing obligations including indemnity obligations related to environmental condition and other matters under the Calumet facility sale agreement which was effective May 31, 2005. Wisconsin Energy's maximum aggregate
exposure under the indemnification provisions of the Calumet facility sale agreement, except for retention of the full exposure to indemnify for environmental claims related to certain property no longer leased or owned by Wisconsin Energy or its subsidiaries, is $35 million.
Wisconsin Energy's other guarantees support an environmental indemnification, which is unlimited, associated with the Minergy Neenah plant and indemnifications related to the post-closing obligations under the Minergy Neenah sale agreement which was effective September 7, 2006.
Wisconsin Energy's other guarantees also support obligations to third parties under purchase and loan agreements and surety bonds. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.
5. During the twelve months ended December 31, 2008, Wisconsin Energy paid $65.6 million in interest, net of amounts capitalized, and $1.3 million in income taxes, net of refunds. During the twelve months ended December 31, 2007, Wisconsin Energy paid $63.5 million in interest, net of amounts capitalized, and received $70.5 million in refunds from income taxes. During the twelve months ended December 31, 2006, Wisconsin Energy paid $62.4 million in interest, net of amounts capitalized, and $32.0 million in income taxes, net of refunds.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WISCONSIN ENERGY CORPORATION
By
/s/GALE E. KLAPPA
Date:
February 27, 2009
Gale E. Klappa, Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/GALE E. KLAPPA
February 27, 2009
Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director -- Principal Executive Officer
/s/ALLEN L. LEVERETT
February 27, 2009
Allen L. Leverett, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer
/s/STEPHEN P. DICKSON
February 27, 2009
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer
/s/JOHN F. BERGSTROM
February 27, 2009
John F. Bergstrom, Director
/s/BARBARA L. BOWLES
February 27, 2009
Barbara L. Bowles, Director
/s/PATRICIA W. CHADWICK
February 27, 2009
Patricia W. Chadwick, Director
/s/ROBERT A. CORNOG
February 27, 2009
Robert A. Cornog, Director
/s/CURT S. CULVER
February 27, 2009
Curt S. Culver, Director
/s/THOMAS J. FISCHER
February 27, 2009
Thomas J. Fischer, Director
/s/ULICE PAYNE, JR.
February 27, 2009
Ulice Payne, Jr., Director
/s/FREDERICK P. STRATTON, JR.
February 27, 2009
Frederick P. Stratton, Jr., Director
WISCONSIN ENERGY CORPORATION
(Commission File No. 001-09057)
EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 2008
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Energy Corporation. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)
E-7