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 Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (We Power).
Utility Energy Segment: Our utility energy segment consists of Wisconsin Electric and Wisconsin Gas, operating together under the trade name of "We Energies." We Energies serves approximately 1,122,500 electric customers in Wisconsin and the Upper Peninsula of Michigan. We Energies serves approximately 1,068,200 gas customers in Wisconsin and approximately 465 steam customers in metropolitan Milwaukee, Wisconsin.
Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power, which owns and leases to Wisconsin Electric generation plants constructed as part of our PTF strategy. All four of the plants constructed as part of PTF have been placed in service. Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2) are being leased to Wisconsin Electric under long-term leases that run for 25 years. Oak Creek expansion Unit 1 (OC 1) and Oak Creek expansion Unit 2 (OC 2) are being leased to Wisconsin Electric under long-term leases that run for 30 years.
For further financial information about our business segments, see Results of Operations in Item 7 and Note P -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.
Reclassifications: On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information in this report has been restated for all periods presented to reflect this stock split.
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. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy in a territory that includes southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and the Upper Peninsula of Michigan.
Wisconsin Electric participates in the MISO Energy Markets. The competitiveness of our generation offered in the MISO Energy Markets affects 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 totaled approximately 31.3 million MWh during 2011 and approximately 30.5 million MWh during 2010. We had approximately 1,122,500 electric customers as of December 31, 2011 and 1,120,200 electric customers as of December 31, 2010.
Wisconsin Electric is authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits, Certificates of Public Convenience and Necessity (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.
Electric Sales Growth: Our service territory continued to experience growth in 2011 in sustained recovery from the significant economic recession that occurred during late 2008 and 2009. Our normalized 2011 retail electric sales, excluding our two largest customers, two iron ore mines, were approximately 0.4% higher than our normalized 2010 electric sales. As we look toward 2012 and beyond, we presently anticipate that total retail electric kWh sales of our utility energy segment and the associated peak electric demand will grow at annual rates of 0.5% to 1.0% over the next five years. These estimates assume normal weather and exclude the two iron ore mines.
Sales to Large Electric Retail Customers: We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, as well as to large retail chains.
Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan. The combined electric energy sales to the two mines accounted for 7.1% and 6.9% of our total electric utility energy sales during 2011 and 2010, respectively. The mines have notified us that they expect production at one of the mines to be reduced in 2012.
Sales to Wholesale Customers: During 2011, we sold wholesale electric energy to one municipally owned system, two rural cooperatives and two municipal joint action agencies located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to 14 other public utilities and power marketers throughout the region under rates approved by FERC. Wholesale sales accounted for approximately 13.1% of our total electric energy sales and 7.0% of total electric operating revenues during 2011, compared with 10.2% of total electric energy sales and 6.0% of total electric operating revenues during 2010.
Electric System Reliability Matters: Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. The Public Service Commission of Wisconsin (PSCW) has planning reserve requirements consistent with the MISO calculated planning reserve margin. The Michigan Public Service Commission (MPSC) has not yet established guidelines in this area. In accordance with the MISO calculated planning reserve margin requirements, we had adequate capacity to meet all of our firm electric load obligations during 2011 and expect to have adequate capacity to meet all of our firm obligations during 2012. 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 energy from plants using 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 Nuclear Power Plant (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 as of 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)
The increase in 2011 as compared to 2010 reflects the January 2011 in-service date of OC 2, partially offset by the March 2011 sale of our interest in Edgewater Generating Unit 5. The increase in 2010 as compared to 2009 reflects the February 2010 in-service date of OC 1. Our share of the dependable capability of OC 1 and OC 2 is 528 MW each.
(c)
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.
(d)
Includes hydroelectric and wind generation. The increase in 2011 as compared to 2010 reflects the December 2011 in-service date of the Glacier Hills Wind Park. For purposes of measuring dependable capability, the 162 MW Glacier Hills Wind Park has a dependable capability of 32 MW and the 145 MW Blue Sky Green Field wind project has a dependable capability of 29 MW.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2011, as well as an estimate for 2012:
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 continued to see volatility in pricing due to increased domestic and world-wide demand for coal and the impacts of diesel costs which are incorporated into fuel surcharges on rail transportation.
Natural gas costs have been volatile. We have a PSCW-approved hedging program to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the average costs of natural gas and purchased power shown above.
Coal-Fired Generation
Coal Supply: We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming, Pennsylvania and Montana, as well as from various other states. During 2012, 100% of our projected coal requirements of 9.7 million tons are under contracts which are not tied to 2012 market pricing fluctuations. At the end of 2011, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,880 MW.
The annual tonnage amounts contracted for 2012 through 2014 are as follows:
Coal Deliveries: Approximately 100% of our 2012 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 and Pleasant Prairie Power Plants from Wyoming mines, and transport coal for the Oak Creek expansion units from Pennsylvania and West Virginia. Coal from a Montana mine is also transported via rail to Lake Michigan transfer docks and delivered by lake vessel to the Milwaukee harbor for Milwaukee-based power plants. Montana and Wyoming coal for the Presque Isle Power Plant is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery.
Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded; therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices. We have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. The costs of this program are included in our fuel and purchased power costs.
Edgewater Generating Unit 5: On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. (WPL), for our net book value, including working capital, of approximately $38 million.
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 four operating plants with a dependable capability of approximately 1,983 MW as of December 31, 2011.
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.
We have a PSCW-approved hedging program that allows us to hedge up to 65% of our estimated gas usage for electric generation in order to help manage our natural gas price risk. The costs of this program are included in our fuel and purchased power costs.
Oil-Fired Generation
Fuel oil is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at the Presque Isle Power Plant, and diesel engines at the Pleasant Prairie Power Plant and Valley Power Plant (VAPP). Our oil-fired generation had a dependable capability of approximately 257 MW as of December 31, 2011. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. 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, 2011. 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, is operated under a permit granted by another agency of the federal government.
Wind: The Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW and a dependable capability of 29 MW, commenced commercial operation in May 2008. The Glacier Hills Wind Park, which has 90 turbines with an installed capacity of 162 MW and a dependable capability of 32 MW, commenced commercial operation in December 2011.
Biomass: We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar's sustainable papermaking operations. Construction commenced on June 27, 2011. We currently expect to invest between $245 million and $255 million, excluding Allowance for Funds Used During Construction (AFUDC), in the plant and we expect the plant to be completed during the fall of 2013.
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 as of December 31, 2011 with unaffiliated parties for the next five years:
The above commitments include approximately 1,030 MW per year related 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 is a regional transmission company that owns, maintains, monitors and operates electric transmission systems in Wisconsin, Michigan and Illinois. ATC is expected to provide comparable service to all customers, including Wisconsin Electric, 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 is a non-transmission owning member and customer of MISO. We owned approximately 26.2% of ATC as of December 31, 2011 and 2010. For additional information, see Note Q -- Related Parties in the Notes to Consolidated Financial Statements.
In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company (DATC), that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity.
MISO: In connection with its status as a FERC approved Regional Transmission Organization (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 the 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 Utility Operating Statistics
The following table shows certain electric utility operating statistics for the past five years:
(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 operating under the trade name of "We Energies." We are authorized to provide retail gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits, CPCNs, or boundary agreements with other utilities. We also transport customer-owned gas. We are the largest natural gas distribution utility in Wisconsin and we operate throughout the state, including the City of Milwaukee, west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties.
Gas Deliveries
Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers, and annual gas sales are impacted by the variability of winter temperatures.
Total gas therms delivered, including customer-owned transported gas, were approximately 2,154.1 million therms during 2011, a 2.3% increase compared with 2010. As of December 31, 2011, we were transporting gas for approximately 1,400 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 41.8% of the total volumes delivered during 2011, 43.5% during 2010 and 40.4% during 2009. We had approximately 1,068,200 and 1,064,500 gas customers as of December 31, 2011 and 2010, respectively. Our peak daily send-out during 2011 was 1,545,577 Dth on February 9, 2011.
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, 2016 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. 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 in recent heating seasons.
Pipeline Capacity and Storage: The interstate pipelines serving Wisconsin originate in major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico, western Canada and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.
Due to the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage levels at approximately 35% of winter demand. Storage capacity, along with our gas purchase contracts, 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.
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 Chicago, Illinois market hub and in the 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 approved Gas Cost Recovery Mechanisms (GCRMs). During 2011, we continued to participate 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 New York Mercantile Exchange (NYMEX) based natural gas options and (ii) up to 15% of planned flowing gas supply using NYMEX based natural gas future contracts. 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 GCRMs. Hedge targets (volumes) are provided annually to the PSCW as part of each company's three-year gas supply plan and risk management filing.
To the extent that opportunities develop and our physical supply operating plans will support them, we also have PSCW approval to utilize NYMEX based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRMs.
Gas Utility Operating Statistics
The following table shows certain gas utility operating statistics for the past five years:
(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: Our steam utility generates, distributes and sells steam supplied by our VAPP and Milwaukee County Power Plant. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from VAPP, a coal-fired cogeneration facility. We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.
Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2011, the steam utility had $39.0 million of operating revenues from the sale of 2,733 million pounds of steam compared with $38.8 million of operating revenues from the sale of 2,740 million pounds of steam during 2010. As of December 31, 2011 and 2010, steam was used by approximately 465 customers and 460 customers, respectively, for processing, space heating, domestic hot water and humidification.
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 consists primarily of generating plants constructed as part of our PTF strategy. As of December 31, 2011, our PTF assets represented virtually all of our non-utility energy segment assets.
We Power
We Power, through wholly owned subsidiaries, has designed and built approximately 2,320 MW of new generation in Wisconsin, which is being leased to Wisconsin Electric under long-term leases. This new generation consists of approximately 1,230 MW of new capacity from OC 1 and OC 2, and 1,090 MW of capacity from PWGS 1 and PWGS 2. PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. In November 2005, two unaffiliated entities collectively purchased an ownership interest of approximately 17%, or 200 MW, in OC 1 and OC 2. Similar to the generating capacity at PWGS 1 and PWGS 2, We Power owns the remaining generating capacity at OC 1 and OC 2.
Our PTF strategy was designed to address Wisconsin Electric's electric supply needs by increasing the electric generating capacity in Wisconsin while allowing us to maintain a diversified fuel mix, by including both new coal-fired plants and natural-gas fired plants. Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which became effective in August 2001 and allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four PTF units were constructed under leases approved by the PSCW. For additional background information on our PTF strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Corporate Developments - Corporate Strategy - Power the Future Strategy and - Factors Affecting Results, Liquidity and Capital Resources - Power the Future in Item 7 of our Form 10-K for the year ended December 31, 2007.
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 discontinued its development activity. As of December 31, 2011, 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 and Bostco LLC
Wispark and Bostco develop and invest in real estate, and combined had $85.0 million in real estate holdings as of December 31, 2011. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.
REGULATION
Wisconsin Energy Corporation
Wisconsin Energy is a holding company, but is exempt from the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005).
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 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, 2011.
Utility Energy Segment
Wisconsin Electric is a holding company because of its ownership interest in ATC, but is exempt from the requirements of PUHCA 2005.
Wisconsin Electric is subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities and modify certain other aspects of energy regulations and Federal tax policies applicable to Wisconsin Electric. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.
Wisconsin Electric and Wisconsin Gas are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. Wisconsin Electric is also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric is subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Wisconsin Electric's hydroelectric facilities are regulated by FERC. Wisconsin Electric is subject to the regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting and with respect to our participation in the interstate natural gas pipeline capacity market. 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, 2011:
The operations of Wisconsin Electric and Wisconsin Gas are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Environmental Quality and the Michigan Department of Natural Resources.
Public Benefits and Renewable Portfolio Standard
Wisconsin Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under this act, we must meet certain minimum requirements for renewable energy generation. For the years 2010 through 2014, we must increase our percentage of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from our baseline renewable percentage of 2.27% to a level of 4.27%. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. As of December 31, 2011, we are in compliance with the Wisconsin renewable energy percentage 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%. In addition, under this Act, 1.5% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2011. The funding required by Act 141 decreased to 1.2% of annual operating revenues in 2012.
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 - Renewable Energy Portfolio 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 that constructed this new generating capacity (collectively, the We Power project companies). These facilities are being leased on a long-term basis to Wisconsin Electric. We Power received determinations from FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies are not deemed public utilities under the Federal Power Act and thus are not subject to FERC's jurisdiction.
Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.
ENVIRONMENTAL COMPLIANCE
Our operations are subject to extensive environmental regulations by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental statutes and regulations or revisions to existing laws, including for example, additional regulation of greenhouse gas emissions, coal combustion products, air emissions or wastewater discharges, could significantly increase these environmental compliance costs.
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. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality, see Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.
Compliance with federal, state and local environmental protection requirements resulted in capital expenditures by Wisconsin Electric of approximately $120.3 million in 2011 compared with $215.5 million in 2010. Expenditures incurred during 2011 and 2010 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric's power plants. These expenditures are expected to be approximately $71.0 million during 2012, reflecting the addition of Nitrogen Oxide (NOx), Sulfur Dioxide (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 $79.0 million and $76.2 million during 2011 and 2010, respectively.
Coal Combustion Product Fills and Landfills
We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Some early designed and constructed coal combustion product 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. In addition, fill areas for coal ash were used prior to the introduction of landfill regulations. Sites currently undergoing review include the following:
Oak Creek Site Landfills: Groundwater impacts identified near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, prompted Wisconsin Electric to begin investigation in 2009 for the source of impacts found in monitoring wells on the site and surrounding area. Preliminary results indicate that the groundwater impacts may be naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of elements deeper in the ground. The WDNR began sampling work in 2011 to identify the source of the impacts.
See Item 3 Legal Proceedings -- Environmental Matters for a discussion of the bluff collapse at our Oak Creek Power Plant.
OTHER
Research and Development: We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations. Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.
Employees: As of December 31, 2011, we had the following number of employees:
The employees represented under labor agreements were with the following bargaining units as of December 31, 2011:
ITEM 1A.
ITEM 1A.
RISK FACTORS
Risks Related to the Operation of Our Business
Our business is significantly impacted by governmental regulation.
We are subject to significant state, local and federal governmental regulation. We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Further, Wisconsin Electric's hydroelectric facilities are regulated by FERC, and FERC also regulates our wholesale power service practices, electric reliability requirements, and participation in the interstate natural gas pipeline capacity market. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.
We are obligated to comply in good faith with all applicable governmental rules and regulations. If it is determined that we failed to comply with any applicable rules or regulations, whether through new interpretations or applications of the regulations or otherwise, we may be liable for customer refunds, penalties and other amounts, which could materially and adversely affect our results of operations and financial condition.
We estimate that within our regulated energy segment, approximately 86% of our electric revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. All of our natural gas and steam revenues are regulated by the PSCW. Our ability to obtain rate adjustments in the future is dependent upon regulatory action, and there can be no assurance that we will be able to obtain rate adjustments in the future that will allow us to recover our costs and expenses and to maintain our current authorized rates of return.
We believe we have obtained the necessary permits, approvals and certificates for our existing operations and that our respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to us cannot be predicted. Changes in regulation, interpretations of regulations or the imposition of additional regulations could influence our operating environment and may result in substantial compliance costs.
Governmental agencies could modify our permits, authorizations or licenses.
Wisconsin Electric and Wisconsin Gas are required to comply with the terms of various permits, authorizations and licenses. These permits, authorizations and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.
Also, if we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other associated costs in our rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.
Factors beyond our control could adversely affect project costs and completion of major construction projects.
We are in the process of constructing new renewable generation and adding environmental controls equipment to existing generating facilities. These types of large construction projects 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 ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other
governmental actions; and events in the global economy.
If we are unable to complete the development or construction of a facility or decide to delay or cancel construction, we may not be able to recover our investment in the facility and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these costs in rates. In addition, construction delays can result in the delay of revenues and, therefore, could affect our results of operations.
We estimate that the final cost of the Oak Creek expansion is approximately $181 million, or 8.3%, over the amount initially approved by the PSCW, of which our share is approximately $154 million. This additional amount includes the amounts payable to Bechtel Power Corporation (Bechtel) pursuant to the Settlement Agreement. The order approving the Oak Creek expansion provides that if final costs are within 5% of the costs initially approved by the PSCW, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion to be recovered from Wisconsin Electric's ratepayers 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 that such costs were prudently incurred and were the result of force majeure conditions, an excused event and/or an event of loss. In addition, the leases provided for a guaranteed in-service date of September 29, 2009 for OC 1 and September 29, 2010 for OC 2, and imposed liquidated damages of $250,000 per day, of which Elm Road Generating Station Supercritical, LLC's (ERGSS) share is approximately $208,350 per day, for failure to achieve the guaranteed in-service date unless the delays resulted from force majeure conditions or an excused event. ERGSS is entitled to receive its share of liquidated damages from Bechtel for each day Bechtel failed to achieve the same guaranteed in-service dates, unless the delays resulted from force majeure conditions or an excused event. Bechtel was granted total schedule relief of 120 days for OC 1 and 81 days for OC 2. All liquidated damages collected are for the benefit of Wisconsin Electric's customers. There is no guarantee that the PSCW will grant ERGSS the same schedule relief. In light of the weather delays incurred on the project and other factors, we expect to request authorization from the PSCW to recover all costs associated with the units and to grant relief from liquidated damages. If the PSCW does not allow Wisconsin Electric to collect our share of the additional costs or grant ERGSS the same schedule relief, our results of operations could be adversely affected.
Customer growth in our service areas affects our results of operations.
Our results of operations are affected by customer growth in our service areas. Customer growth can be affected by population growth as well as economic factors in Wisconsin and the Upper Peninsula of Michigan, including job and income growth. Customer growth directly influences the demand for electricity and gas, and the need for additional power generation and generating facilities. Population declines and/or business closings in our service territories or slower than anticipated customer growth has a negative impact on our results of operations and cash flow.
Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.
Our electric and gas utility businesses are generally seasonal businesses. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Mild temperatures during the summer cooling season and during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.
Severe weather events, such as floods, droughts, tornadoes and blizzards, could result in substantial damage to or limit the operation of our facilities.
Severe weather events could result in substantial damage to our electric generating and gas distribution facilities, as well as ATC's transmission lines. Our hydroelectric generation operations could be adversely affected if there is a significant change in water levels in their respective waterways. In addition, a significant reduction in water levels in waterways that supply cooling water to our coal- and natural gas-fired power plants, whether by drought or otherwise, could restrict or prevent the operation of such facilities.
In the event we experience any of these weather events or other natural disaster, recovery of any costs in excess of any reserves or applicable insurance is subject to the approval of the PSCW and/or MPSC. There is no guarantee that we will be allowed to fully recover any such costs or that cost recovery will not be delayed or otherwise conditioned. Any denial or delay in recovery of any such costs could adversely affect our results of operations and cash flows.
In addition, damages resulting from severe weather events within our service territories may result in the loss of customers and reduced demand for electricity and natural gas for extended periods. Any significant loss of customers or reduction in demand could adversely affect our results of operations and cash flows.
Our financial performance may be adversely affected if we are unable to successfully operate our facilities.
Our financial performance depends on the successful operation of our electric generating and gas distribution facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. Unplanned outages can result in additional maintenance expenses as well as incremental replacement power costs. A decrease in revenues from these facilities or an increase in operating costs could adversely affect our results of operations and cash flows.
We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.
As a holding company, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. The ability of our subsidiaries to pay amounts to us will depend on the earnings, cash flows, capital requirements and general financial condition of our subsidiaries and on regulatory limitations. Prior to distributing cash to Wisconsin Energy, our subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. Our subsidiaries also have dividend payment restrictions based on the terms of their outstanding preferred stock and regulatory limitations applicable to them. In addition, each of the bank back-up credit facilities for Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have specified total funded debt to capitalization ratios that must be maintained. Wisconsin Energy's subsidiaries are separate legal entities and have no obligation to provide us with funds for our payment obligations.
An increase in natural gas costs could negatively impact our electric and gas utility operations.
Wisconsin Electric burns natural gas in several of its peaking power plants and in PWGS 1 and PWGS 2, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. Disruption in the supply of natural gas due to a curtailment in production or distribution can increase the cost of natural gas, as can international market conditions and demand for natural gas. Higher natural gas costs can have the effect of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well.
For Wisconsin customers, Wisconsin Electric bears the risk for the recovery of fuel and purchased power costs within a symmetrical two percent fuel tolerance band compared to the forecast of fuel and purchased power costs established in its rate structure. Our gas distribution business receives dollar for dollar recovery of the cost of natural gas, subject to tolerance bands and prudency review. However, increased natural gas costs increase the risk that customers will switch to alternative sources of fuel or reduce their usage, which could reduce future gas margins. In addition, an increase in natural gas costs combined with slower economic conditions could also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Additionally, high natural gas costs increase our working capital requirements.
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.
We are dependent on coal for much of our electric generating capacity. Although we currently have an adequate supply of coal at our coal-fired facilities, there can be no assurance that we will continue to have an adequate supply of coal in the future. While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill
their obligations to us. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, international demand for coal can impact its availability and cost. If we significantly reduce our inventory of coal and are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to reduce generation at our coal units and replace this lost generation from higher cost generating resources or through additional power purchases in the MISO Energy Markets.
Acts of terrorism could materially and adversely affect our financial condition and results of operations.
Our electric generation and gas distribution facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, purchase or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations and financial condition.
We could be the subject of cyber intrusions that disrupt our electric generation and gas distribution operations and/or result in security breaches that expose us to a risk of loss or misuse of confidential and proprietary information, litigation and potential liability.
Cyber intrusions, including those targeting the electronic control systems used at our generating facilities and for the electric and gas distribution systems, could result in a full or partial disruption of our electric generation and/or gas distribution operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchased power to meet customer demand for electricity if our electric generating facilities are unable to operate at full capacity as a result of a cyber intrusion. Any resulting loss of revenue or increase in expense could have a material adverse effect on our results of operations, cash flow and financial condition.
In addition, any theft, loss and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers, stockholders and regulators, among others.
As cyber attacks become more sophisticated generally, we may be required to incur significant costs to strengthen our information and electronic control systems from outside intrusions and/or to obtain insurance coverage related to the threat of such attacks.
Wisconsin Electric could be subject to higher costs and penalties as a result of mandatory reliability standards.
Wisconsin Electric is subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation. The critical infrastructure protection standards focus on controlling access to critical and physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject Wisconsin Electric to higher operating costs. If Wisconsin Electric is found to be in noncompliance with the mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties.
A downgrade in the credit ratings of WEC or any of its subsidiaries could negatively affect their ability to access capital at reasonable costs and/or require the posting of collateral.
There are a number of factors that impact Wisconsin Energy's and its subsidiaries' credit ratings, including, without limitation, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. Wisconsin Energy or any of its subsidiaries could experience a downgrade in their ratings if the rating agencies determine that the level of business or financial risk of the industry or Wisconsin Energy and/or its subsidiaries has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If Wisconsin Energy or its subsidiaries are downgraded by the rating agencies, their borrowing costs could increase, funding sources could decrease and, for any downgrade to below investment grade, collateral requirements may be triggered in several contracts.
Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.
Events such as an aging workforce without appropriate replacements may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.
The use of derivative contracts could result in financial losses.
We use derivative instruments such as swaps, options, futures and forwards to manage commodity and, to a much lesser extent, interest rate exposures. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although the hedging programs of Wisconsin Electric and Wisconsin Gas must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.
The Dodd-Frank Act could impact our use of over-the-counter (OTC) derivatives. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of OTC derivatives, which could affect both the use and cost of OTC derivatives. The impact, if any, cannot be determined until the regulations are finalized.
Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.
FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, futures contracts and derivatives are traded on various commodities exchanges. We currently cannot predict the impact of these developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.
Restructuring in the regulated energy industry could have a negative impact on our business.
The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. It is uncertain when retail access might be implemented in Wisconsin; however, Michigan has adopted retail choice which allows customers to choose their own electric generation supplier. Although competition and customer switching to alternative suppliers in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.
FERC continues to support the existing RTOs that affect the structure of the wholesale market within those RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a Locational Marginal Price (LMP) that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an Ancillary Services Market for operating reserves that was simultaneously co-optimized with its existing energy markets.
These market designs have the potential to increase the costs of transmission, the costs associated with inefficient
generation dispatching, the costs of participation in the market and the costs associated with estimated payment settlements.
Risks Related to Legislation and Regulation
We may face significant costs of compliance with existing and future environmental regulations.
Our operations are subject to extensive environmental legislation and regulation by state and federal environmental agencies governing, among other things, air emissions such as Carbon Dioxide (CO2), SO2, NOx, fine particulates and mercury; water discharges; and management of hazardous, toxic and solid wastes and substances. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities. In April 2003, Wisconsin Electric reached a Consent Decree with the EPA to significantly reduce air emissions from its coal-fired generating facilities. Through the end of 2011, we had invested approximately $1.0 billion to comply with the Consent Decree. The total cost of implementing the Consent Decree is currently estimated to be approximately $1.1 billion over the ten year period ending 2013.
Several new environmental regulations have recently been proposed or adopted, including the EPA's Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS) rule (also referred to as the utility Maximum Achievable Control Technology (MACT) rule) and new SO2 National Ambient Air Quality Standards. Various petitioners have requested judicial and administrative review of many of these regulations, including CSAPR. The December 30, 2011 decision of the U.S. Court of Appeals for the District of Columbia to grant a motion to stay CSAPR, which was scheduled to become effective on January 1, 2012, adds substantial uncertainty as to what capital expenditures may be required to comply with new environmental regulations. Despite this uncertainty, we currently estimate the capital expenditures necessary to comply with these new environmental regulations, including the utility MACT rule, over the three year period ending 2014 could be up to $16 million more than the estimated cost of implementing the Consent Decree. These costs are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.
Existing environmental regulations may be revised or new laws or regulations may be adopted at the federal or state level which could result in significant additional expenditures, operating restrictions on our facilities and increased compliance costs. In addition, the operation of emission control equipment and further regulations on our intake and discharge of water could increase our operating costs and could reduce the generating capacity of our power plants.
In the event we are not able to recover all of our environmental expenditures from our customers in the future, our results of operations could be adversely affected.
Environmental legislation and regulation and the related compliance costs could affect future unit retirement and replacement decisions, and could result in some of our coal-fired generating units being retired or converted to an alternative type of fuel. In order to comply with new environmental requirements we are currently exploring different alternatives with regard to the Presque Isle Power Plant in the Upper Peninsula of Michigan and the VAPP in Milwaukee, Wisconsin. We have committed to convert the VAPP from coal to natural gas if we are able to determine that such conversion will have a direct economic benefit to our customers and we receive approval from the PSCW. Costs associated with these potential actions could affect our results of operations and financial condition.
Our electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at certain of our current and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.
We may also be subject to potential liability in connection with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. If we fail (or failed) to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and
damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.
Energy conservation and rate increases could negatively impact financial results.
Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. To the extent there is any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures, these measures could have a negative impact on our results of operations and cash flows.
In addition, any higher costs that are collected through rates could contribute to reduced demand for electricity, natural gas or steam, which could adversely impact our results of operations and financial condition.
We may face significant costs if coal combustion products are regulated as hazardous waste.
We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In June 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products. One of the proposed rules classifies the materials as hazardous waste. We submitted comments on the proposed rules in 2010. The EPA also issued a Notice of Data Availability (NODA) in October 2011, and we submitted comments on the NODA in November 2011. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.
If coal combustion products are classified as hazardous waste and we terminate our coal combustion products utilization program, we could be required to dispose of the coal combustion products at a significant cost to the Company, which could adversely impact our results of operations and financial condition.
In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the Clean Air Act (CAA), and finalized a Non-Hazardous Secondary Materials Rule. Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills.
We may face significant costs to comply with the regulation of greenhouse gas emissions.
The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards has failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Although we cannot currently predict with any certainty what form these future regulations will take, the stringency of the regulations or when they will become effective, we do believe that future governmental legislation and/or regulation may require us to limit or control greenhouse gas emissions from our operations, purchase allowances for such emissions or otherwise incur costs in connection with such emissions.
While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In December 2009, the EPA issued its endangerment finding related to greenhouse gas emissions, which set in motion a regulatory process that has led to the regulation of greenhouse gas emissions from stationary sources, including electric generating units. In March 2010, the EPA issued regulations governing the applicability of the CAA's permitting requirements for greenhouse gas emissions from facilities, including electric generating units. These rules became applicable to sources that are already subject to CAA permitting requirements, as well as new and modified sources, during 2011. Additionally, the EPA plans to propose new source performance standards pertaining to greenhouse gas emissions from certain new or modified coal-fired power plants by the end of May 2012. Regulation of greenhouse gas emissions from power plants may negatively impact our ability to perform maintenance or modify our existing facilities, and permit new facilities. Depending on the extent of rate recovery and other factors, these rules could have a material adverse impact on our financial condition.
Legislation to regulate greenhouse gas emissions and establish renewable and efficiency standards has also been considered on the state level. The state of Michigan has enacted legislation that calls for the implementation of a
renewable portfolio standard by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. The state of Wisconsin has adopted its own renewable portfolio standard and energy optimization targets. Although the Wisconsin legislature ultimately did not pass a legislative proposal to increase Wisconsin's renewable portfolio standard and energy optimization targets, there is no guarantee the legislature will not consider similar legislation in the future.
Some states and environmental groups are also bringing lawsuits against electric utilities and others to force reductions in greenhouse gas emissions based upon their contribution to the alleged public nuisance of climate change. On June 20, 2011, in Connecticut v. American Electric Power Co., however, the United States Supreme Court ruled that the plaintiffs in that litigation did not have standing to claim nuisance due to the release of greenhouse gas into the atmosphere by the defendants, and the plaintiffs have since voluntarily dismissed their remaining claims. Similar cases are pending in other courts.
There is no guarantee that we will be allowed to fully recover costs incurred to comply with any future legislation, regulation or order that requires a reduction in greenhouse gas emissions or that cost recovery will not be delayed or otherwise conditioned. Any cap-and-trade or greenhouse gas tax program that may be adopted, either at the federal or state level, or other legislation, regulation or order designed to reduce greenhouse gas emissions could have a material adverse impact on our electric generation and natural gas distribution operations. Such regulation could make some of our electric generating units uneconomic to maintain or operate, and could adversely affect our future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.
We continue to monitor the legislative, regulatory and legal developments in this area. Although we expect the regulation of greenhouse gas emissions to have a material impact on our operations and rates, we believe it is premature to attempt to quantify the possible costs of the impacts.
Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.
Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Act, 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 in the system.
In addition, the Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors and the public. This provision and other requirements of the Act may delay or reduce the likelihood of a sale or change of control of Wisconsin Energy. As a result, stockholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.
Risks Related to Economic and Market Volatility
Our business is dependent on our ability to successfully access capital markets.
We rely on access to short-term and long-term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities and common stock. Successful implementation of our long-term business strategies is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, under competitive terms and rates. In addition, we rely on committed bank credit agreements as back-up liquidity which allows us to access the low cost commercial paper markets. If our access to any of these markets were limited, or our cost of capital significantly increased, due to a rating downgrade, an economic downturn or uncertainty, prevailing market conditions, concerns over foreign economic conditions and/or the ability of foreign governments and central banks to respond to changing economic conditions, a negative view of the utility industry, failures of financial institutions or other factors, our results of operations and financial condition could be materially and adversely affected.
We are exposed to risks related to general economic conditions in our service territories.
Our electric and gas utility businesses are impacted by economic cycles and the competitiveness of the customers we serve. As the demand for products produced in our service area declines, we ordinarily experience reduced demand for electricity and/or natural gas. During 2011, our service territory experienced growth, but future growth could be impacted by the overall economy in our service territories. If the economic conditions in our service territories and/or demand for products produced in our service area does not continue to improve or declines again, we could experience a reduction in demand for electricity and/or natural gas that could result in decreased earnings and cash flow. We would also expect our collections of accounts receivable to be adversely impacted.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.
Our cost of providing defined benefit pension plans is dependent upon a number of factors including actual plan experience and assumptions concerning the future, such as earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions to be made to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. A decline in the market value of these assets, as experienced in prior periods, may increase our funding requirements. Changes in interest rates affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact current and future pension costs. These additional funding obligations could have a material adverse impact on our cash flows, financial condition or results of operations.
Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business, as well as by international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. A loss for which we are not fully insured could have a material adverse effect on our results of operations. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject.
ITEM 1B.
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, 2011, 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 are established by tests and may change slightly from year to year.
As of December 31, 2011, we operated approximately 21,632 pole-miles of overhead distribution lines and 23,780 miles of underground distribution cable, as well as approximately 350 distribution substations and 287,446 line transformers.
As of December 31, 2011, our gas distribution system included approximately 20,687 miles of distribution and transmission mains connected at 183 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., 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 2,960 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, 2011, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 43 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.
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 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 our existing facilities are in material compliance with applicable environmental requirements.
Bluff Collapse: On October 31, 2011, a portion of the bluff at our Oak Creek Power Plant collapsed. The affected area, located south of the Air Quality Control System (AQCS) that is currently under construction, was a former ravine that had been filled with coal ash prior to the advent of landfill regulations.
It is estimated that approximately 23,000 cubic yards of soil, coal ash and water was released from the bluff. This mixture of materials, along with several trailers, vehicles and other construction materials from the AQCS construction site, slid down the bluff to the shoreline area. Some of the soil and coal ash mixture fell into Lake Michigan.
We worked with the U.S. Coast Guard, WDNR and EPA to coordinate an incident action plan for completing the recovery and clean-up efforts. Ash and soil materials have been removed from the area, and construction equipment and related materials have been removed from Lake Michigan. The clean-up work has been completed, and the bluff has been stabilized for the winter. We expect that permanent bluff stabilization efforts will commence during the second quarter of 2012.
We have consulted with nearby water utilities who have indicated that they have not detected any impacts to public drinking water supplies. In November 2011, the WDNR conducted a survey of Lake Michigan's lakebed. The survey did not locate any fly ash or construction materials on the lakebed immediately east and south of the Oak Creek site. Both water quality and sediment sampling have not indicated a serious risk of harm to human health or the environment.
We anticipate the WDNR will release its investigative findings during the first quarter of 2012. At this time, we cannot predict with certainty whether the WDNR or other regulatory agency will seek fines or penalties from us as a result of this incident.
In addition, on November 8, 2011, the Sierra Club provided a Notice of Intent to file a citizens suit under the CAA and Resource Conservation and Recovery Act for alleged violations related to this incident. We have responded that we do not believe there is any basis for a citizen suit. To date, Sierra Club has not indicated whether they intend to file suit.
Solvay Coke and Gas Site: Wisconsin Electric and Wisconsin Gas have been identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. 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. In 2007, Wisconsin Electric, Wisconsin Gas and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. In-field investigation activities have commenced. Under the Administrative 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. The companies' share of the costs to perform the required work 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 R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.
Edgewater Generating Unit 5: In December 2009, the EPA issued a Notice of Violation (NOV) concerning several coal-fired power plants owned and operated by WPL, including Edgewater Generating Unit 5, of which Wisconsin Electric owned 25%. Due to its ownership interest at the time, Wisconsin Electric was named in the NOV. On March 1, 2011, Wisconsin Electric sold its interest to WPL. Although Wisconsin Electric sold its interest, it retained its share of liability, if any, related to the NOV. The NOV alleges that certain maintenance projects at WPL's units, including Edgewater 5, were undertaken without obtaining air permits required by the CAA. Wisconsin Electric, WPL and the co-owners of the other plants identified in the NOV are discussing resolution of this NOV with the EPA. At this time, we cannot predict the outcome of this matter.
In September 2010, the Sierra Club filed a complaint against WPL generally alleging air permitting and opacity violations at the Edgewater Generating Station. Wisconsin Electric is not a named party to this litigation. WPL, the other co-owner of the Edgewater Generating Station, and Wisconsin Electric as a former co-owner, are discussing resolution of this matter with the Sierra Club. At this time, we cannot predict the outcome of this matter.
See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, Coal Combustion Product Landfill Sites and EPA - Consent Decree in Note R -- 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 combustion product landfills, manufactured gas plant sites and air quality.
UTILITY RATE MATTERS
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information concerning rate matters in the jurisdictions where Wisconsin Electric and Wisconsin Gas 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 United States Department of Energy's (DOE) 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: Dairy farmers continue to make claims 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.
Cash Balance Pension Plan: See Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7 and Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements for information regarding a lawsuit filed against the Plan.
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 Settlement Agreement with Bechtel, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future and Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not Applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 2011 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 61.
•
Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President since April 2003.
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Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
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Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
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Director of Joy Global, Inc. and Badger Meter, Inc.
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Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.
Charles R. Cole. Age 65.
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Wisconsin Electric -- Senior Vice President since 2001.
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Wisconsin Gas -- Senior Vice President since July 2004.
Mr. Cole is retiring effective March 1, 2012.
Stephen P. Dickson. Age 51.
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Wisconsin Energy -- Vice President since 2005. Controller since 2000.
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Wisconsin Electric -- Vice President since 2005. Controller since 2000.
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Wisconsin Gas -- Vice President since 2005. Controller since 1998.
James C. Fleming. Age 66.
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Wisconsin Energy -- General Counsel since March 2006. Executive Vice President since January 2006.
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Wisconsin Electric -- General Counsel since March 2006. Executive Vice President since January 2006.
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Wisconsin Gas -- General Counsel since March 2006. Executive Vice President since January 2006.
Mr. Fleming is retiring effective April 1, 2012.
J. Kevin Fletcher. Age 53.
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Wisconsin Electric -- Senior Vice President since October 2011.
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Wisconsin Gas -- Senior Vice President since October 2011.
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Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
Robert M. Garvin. Age 45.
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Wisconsin Energy -- Senior Vice President since April 2011.
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Wisconsin Electric -- Senior Vice President since April 2011.
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Wisconsin Gas -- Senior Vice President since April 2011.
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American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.
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NextEra Energy Resources -- Vice President from 2007 to 2009.
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Commissioner - Public Service Commission of Wisconsin -- 2001 to 2007.
Frederick D. Kuester. Age 61.
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Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer since March 2011.
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Wisconsin Electric -- Executive Vice President since May 2004. Chief Operating Officer from October 2003 until February 2011. Chief Financial Officer since March 2011.
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Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer since March 2011.
Mirant Corporation, of which Mr. Kuester was Senior Vice President - International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia - Pacific Limited from 1999 to October 2003, and certain of its subsidiaries
voluntarily filed for bankruptcy in July 2003. Other than certain Canadian subsidiaries, none of Mirant's international subsidiaries filed for bankruptcy.
Allen L. Leverett. Age 45.
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Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.
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Wisconsin Electric -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.
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Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.
Kristine A. Rappé. Age 55.
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Wisconsin Energy -- Senior Vice President and Chief Administrative Officer since May 2004.
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Wisconsin Electric -- Senior Vice President and Chief Administrative Officer since May 2004.
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Wisconsin Gas -- Senior Vice President and Chief Administrative Officer since May 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, 2011, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 42,550 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 I -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.
On January 19, 2012, our Board of Directors approved a new dividend policy. Pursuant to this new policy, we will target a dividend payout ratio that trends toward 60% in the year 2014. At the same time, in accordance with that policy, our Board of Directors increased our quarterly dividend to $0.30 per share effective with the first quarter 2012 dividend payment, which would result in annual dividends of $1.20 per share.
On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. Stockholders of record at the close of business on February 14, 2011 were entitled to one additional share of Wisconsin Energy common stock for each share then owned. The additional
shares were distributed on March 1, 2011. The table below reflects the impact of the two-for-one stock split.
Range of Wisconsin Energy Common Stock Prices and Dividends:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
All shares reported during October 2011 were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.
(b)
On May 5, 2011, Wisconsin Energy's Board of Directors authorized a share repurchase program for up to $300 million of our common stock through December 31, 2013.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(a)
Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's Discussion and Analysis of Financial Condition and Results of Operations.
(b)
Quarterly earnings per share may not total to the amounts reported for the year because the computation is based on the weighted average common shares outstanding during each quarter.
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 primarily consists of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies." We generate and distribute electricity in Wisconsin and the Upper Peninsula of Michigan and we distribute natural gas in Wisconsin. 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 have three primary investment opportunities and earnings streams: our regulated utility business; our investment in ATC; and our generation plants within our non-utility energy segment.
Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve the electric and gas customers of We Energies. During 2011, our regulated utility earned $544.8 million of operating income. Over the next three years, we expect to invest approximately $2.0 billion in this business to construct renewable generation and environmental projects at our electric generation assets, to update the electric and gas distribution infrastructure, and for other utility projects.
We have a $349.7 million investment in ATC, which represents a 26.2% ownership interest. Our 2011 pre-tax earnings from ATC totaled $62.5 million and we received $49.7 million in dividends from ATC. Over the next three years, we expect to invest approximately $29.4 million in ATC as it continues to upgrade the transmission infrastructure within Wisconsin.
Our non-utility energy segment consists primarily of the four generation plants constructed as part of our PTF strategy. All four plants have been placed in service and are being leased to Wisconsin Electric under long-term leases that run for 25 years (PWGS 1 and PWGS 2) and 30 years (OC 1 and OC 2). We recognize revenues on a levelized basis over the life of the lease. During 2012, we expect this segment's operating income to be between $345 million and $350 million. Over the next three years, we expect to invest approximately $75 million in this segment. The PTF strategy was developed with the primary goal of constructing the four power plants discussed above. With the completion of the final PTF unit, OC 2, in January 2011, we believe that our future capital expenditures in this segment will consist primarily of smaller capital projects within the existing PTF units.
RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
The following table compares our operating income by business segment and our net income for 2011, 2010 and 2009:
An analysis of contributions to operating income by segment and a more detailed analysis of results follows.
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
The following table summarizes our utility energy segment's operating income during 2011, 2010 and 2009:
2011 vs. 2010: Our utility energy segment contributed $544.8 million of operating income during 2011 compared with $564.0 million of operating income during 2010. The decrease in operating income was primarily caused by increased other operation and maintenance expense and unfavorable weather during 2011 as compared to the prior year, partially offset by wholesale electric pricing increases and electric sales growth.
2010 vs. 2009: Our utility energy segment contributed $564.0 million of operating income during 2010 compared with $550.9 million of operating income during 2009. The increase in operating income was primarily caused by favorable weather during 2010, partially offset by unfavorable recoveries of revenues associated with fuel and purchased power in 2010.
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 2011 with similar information for 2010 and 2009, 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 20-year moving average.
Electric Utility Revenues and Sales
2011 vs. 2010: Our electric utility operating revenues increased by $275.0 million, or 9.4%, when compared to 2010. The most significant factors that caused a change in revenues were:
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2011 increase of approximately $198.4 million, reflecting the reduction of Point Beach bill credits to retail customers. For information on the bill credits, see Amortization of Gain below.
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Net pricing increases totaling $48.8 million, which includes rates related to our 2010 fuel recovery request that became effective March 25, 2010, and our request to review 2011 fuel costs that became effective April 29, 2011. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.
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Unfavorable weather as compared to the prior year that decreased electric revenues by an estimated $40.5 million.
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A $20.4 million increase in revenue from energy sold into the MISO Energy Markets, which was driven by increased MWh generation from our Oak Creek expansion units.
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Net economic growth that increased electric revenues by an estimated $16.2 million as compared to 2010.
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Higher MWh sales to our wholesale customers, which increased revenue by an estimated $10.4 million as compared to 2010.
As measured by cooling degree days, 2011 was 11.8% warmer than normal, but 16.0% cooler than 2010. The 1.8% decrease in residential sales volumes in 2011 is primarily attributable to weather. The estimated 1.8% impact of cooler summer weather on our small commercial/industrial sales volumes was almost entirely offset by an estimated 1.5% increase in sales due to modest economic growth. Increased sales to our largest customers, two iron ore mines, accounted for the increase in sales to our large commercial/industrial customers. If these sales are excluded, sales to our large commercial/industrial customers decreased by approximately 1.2% for 2011 as compared to 2010 primarily because of previously announced plant closings.
2010 vs. 2009: Our electric utility operating revenues increased by $251.3 million, or 9.4%, when compared to 2009. The most significant factors that caused a change in revenues were:
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Net pricing increases totaling $121.0 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.
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Favorable weather that increased electric revenues by an estimated $103.4 million as compared to 2009.
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Net economic growth that increased electric revenues by an estimated $43.0 million as compared to 2009.
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2010 pricing increases totaling approximately $32.3 million, reflecting the reduction of Point Beach bill credits to retail customers.
As measured by cooling degree days, 2010 was 98.7% warmer than 2009 and 35.2% warmer than normal. Collectively, retail sales to our residential and small commercial/industrial customers, who are more weather sensitive, increased by 4.4%. Sales to our large commercial/industrial customers increased by 9.0% during 2010 as compared to 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, which represented approximately 6.9% of our annual sales in 2010, increased significantly for the year. If these sales are excluded, sales to our large commercial/industrial customers increased by 3.2% for 2010 as compared to 2009. The $36.5 million decline in Other Operating Revenues primarily relates to regulatory amortizations during 2010 as compared to 2009.
Electric Fuel and Purchased Power Expenses
2011 vs. 2010: Our electric fuel and purchased power costs increased by $67.7 million, or approximately 6.2%, when compared to 2010. This increase was primarily caused by a 2.7% increase in total MWh sales as well as increased coal and related transportation costs, partially offset by lower natural gas prices.
2010 vs. 2009: Our electric fuel and purchased power costs increased by $39.4 million, or approximately 3.7%, when compared to 2009. This increase was primarily caused by a 5.5% increase in total MWh sales, partially offset by a 1.6% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 7.7% increase in generation from our lower cost coal units and a 16.5% decrease in the cost of natural gas used at the Port Washington Generating Station (PWGS), which was sufficient to offset the impact of a 5.7% increase in coal and related transportation costs and the increase in gas generation and purchased power utilized as a result of the increased 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 2011, 2010 and 2009. Operating revenues and cost of gas sold has declined over the last three years due to the decline in the commodity cost of natural gas during this three year period.
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 2011, 2010 and 2009:
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
2011 vs. 2010: Our gas margin increased by $13.8 million, or approximately 3.1%, when compared to 2010 primarily because of an increase in sales volumes as a result of colder winter weather in 2011 as compared to 2010. As measured by heating degree days, 2011 was 7.3% colder than 2010 and 0.3% colder than normal.
Winter weather is the most significant variable for our gas margin.
2010 vs. 2009: Our gas margin decreased by $17.2 million, or approximately 3.8%, when compared to 2009 primarily because of a decline in sales volumes as a result of warmer winter weather in 2010 as compared to 2009. As measured by heating degree days, 2010 was 9.4% warmer than 2009 and 6.5% warmer than normal.
Other Operation and Maintenance Expense
2011 vs. 2010: Our other operation and maintenance expense increased by $26.4 million, or approximately 1.7%, when compared to 2010. Higher maintenance costs at one of our natural gas peaking plants, increased spending on forestry work for our electric distribution system and increased costs associated with the amortization of deferred PTF costs related to wholesale and Michigan customers were the primary drivers of the increase.
Our utility operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages and amortization of regulatory assets. We expect our 2012 other operation and maintenance expense to decrease by $148 million because of the one year elimination of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.
2010 vs. 2009: Our other operation and maintenance expense increased by $214.7 million, or approximately 15.6%, when compared to 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $87.3 million higher in 2010 as compared to 2009. In addition, operation and maintenance expenses at our power plants increased approximately $63.9 million primarily because of the operation of OC 1, which was placed in service in February 2010, and higher maintenance costs at our other power plants. We also had increased operation and maintenance expenses of approximately $20.8 million related to increased reliability maintenance in our distribution system in 2010 and responding to damage caused by a larger number of summer storms compared to 2009. In addition, our benefits expense increased by approximately $28.8 million in 2010 as compared to 2009 primarily because of increased pension costs.
Depreciation and Amortization Expense
2011 vs. 2010: Depreciation and Amortization expense increased by $5.6 million, or approximately 2.2%, when compared to 2010. This increase was primarily because of an overall increase in utility plant in service.
We expect depreciation and amortization expense to increase in 2012 as a result of an increase in utility plant in service related to the Glacier Hills Wind Park, which went in service in December 2011, and the Oak Creek AQCS project, which is scheduled to go in service in 2012.
2010 vs. 2009: Depreciation and Amortization expense decreased by $61.7 million, or approximately 19.7%, when compared to 2009. This decrease was primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.
Amortization of Gain
In connection with the September 2007 sale of Point Beach, we reached an agreement with our regulators to allow for the net gain on the sale to be used for the benefit of our customers. The majority of the benefits were returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it was amortized to the income statement as we issued bill credits to customers. When the bill credits were issued to customers, we transferred cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. All bill credits associated with the sale of Point Beach were applied to customers as of December 31, 2010, and as a result, the Amortization of Gain was zero during 2011 as compared to $198.4 million during 2010 and $230.7 million during 2009.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2). PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. The common facilities associated with the Oak Creek expansion include the water intake system, which was placed in service in January 2009, the coal handling system, which was placed in service in November 2007, and other smaller assets. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively.
The table below reflects:
•
A full year's earnings for 2011, 2010 and 2009 for:
◦
PWGS 1;
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PWGS 2;
◦
the coal handling system for the Oak Creek expansion; and
◦
the water intake system for the Oak Creek expansion
•
A full year's earnings for 2011 and approximately eleven months of earnings for 2010 for OC 1; and
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Approximately eleven and a half months of earnings for 2011 for OC 2.
This segment reflects the lease revenues on the new units as well as the depreciation expense. Operating and maintenance costs and limited management fees associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.
In 2012, we expect our non-utility energy segment to generate slightly higher operating income because OC 2 went into service on January 12, 2011 and changes in the depreciable lives of the plants.
CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME
2011 vs. 2010: Corporate and other affiliates had an operating loss of $6.4 million in 2011 compared with an operating loss of $6.0 million in 2010.
2010 vs. 2009: Corporate and other affiliates had an operating loss of $6.0 million in 2010 compared with an operating loss of $10.7 million in 2009. This change is primarily due to a reduction in other operation and maintenance expense.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET
2011 vs. 2010: Other income and deductions, net increased by approximately $22.5 million, or 56.0%, when compared to 2010. The increase in AFUDC - Equity is primarily related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park.
During 2012, we expect to see a reduction in AFUDC - Equity with the completion of the Glacier Hills Wind park in December 2011 and the expected completion of the Oak Creek AQCS project by the end of 2012.
2010 vs. 2009: Other income and deductions, net increased by approximately $11.7 million, or 41.1%, when compared to 2009. This increase primarily relates to increased AFUDC - Equity related to the construction of the Oak Creek AQCS project.
CONSOLIDATED INTEREST EXPENSE, NET
2011 vs. 2010: Our gross interest costs increased by $3.8 million, or 1.5%, during 2011, primarily because of higher average long-term debt balances as compared to 2010. In January 2011, we issued $420 million of long-term debt and used the net proceeds to repay short-term debt incurred to finance the construction of OC 2 and for other corporate purposes. In September 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. In April 2011, we retired $450 million of long-term debt that matured, which partially offset the debt issuances. Our capitalized interest decreased by $25.6 million primarily because we stopped capitalizing interest on OC 2 when it was placed in service in January 2011. As a result, our net interest expense increased by $29.4 million, or 14.2%, as compared to 2010.
During 2012, we expect to see higher net interest expense because of a reduction in capitalized interest as a result of the Glacier Hills Wind Park project going in service in December 2011 and the expected completion of the Oak Creek AQCS project by the end of 2012.
2010 vs. 2009: Our gross interest costs increased by $23.3 million, or 9.9%, during 2010, primarily because of higher long-term debt balances compared to 2009. In February 2010, we issued $530 million of long-term debt in connection with the commercial operation of OC 1 and used the net proceeds to repay short-term debt incurred during construction. Our capitalized interest decreased by $26.4 million primarily because we stopped capitalizing interest on OC 1 when it was placed in service in February 2010. As a result, our net interest expense increased by $49.7 million, or 31.7%, as compared to 2009.
CONSOLIDATED INCOME TAX EXPENSE
2011 vs. 2010: Our effective tax rate applicable to continuing operations was 34.0% in 2011 compared to 35.5% in 2010. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity. For further information, see Note H -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2012 annual effective tax rate to be between 36% and 37%.
2010 vs. 2009: Our effective tax rate applicable to continuing operations was 35.5% in 2010 compared to 36.5% in 2009. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity and increased production activities tax deductions.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2011, 2010 and 2009:
Operating Activities
2011 vs. 2010: Cash provided by operating activities was $993.4 million during 2011, which was an increase of $183.0 million over 2010. The largest increases in cash provided by operating activities related to higher net income, higher depreciation expense, higher deferred income tax benefits and the elimination of the amortization of the gain on the sale of Point Beach. Combined these items totaled $1,293.2 million during 2011 as compared to $680.4 million during 2010. The largest reduction in cash provided by operating activities related to our contributions to qualified benefit plans. During 2011, we contributed $277.4 million to our qualified benefit plans. We made no contributions to our qualified plans during 2010.
2010 vs. 2009: Cash provided by operating activities was $810.4 million during 2010, which was an increase of $181.5 million over 2009. This increase is primarily related to a $289.3 million contribution to our qualified benefit plans in 2009. No such contributions were made in 2010. This increase was partially offset by an increase in cash paid for taxes during 2010.
Investing Activities
2011 vs. 2010: Cash used in investing activities was $892.5 million during 2011, which was $259.0 million higher than 2010. This increase in cash used primarily reflects changes in restricted cash and increased capital expenditures. During 2011, our restricted cash increased by $37.2 million primarily because of the nuclear fuel settlement we received from the DOE. During 2010, our restricted cash decreased by $186.2 million due to the release of restricted cash related to the Point Beach bill credits. See Nuclear Operations in this report for additional information regarding the settlement with the DOE. In addition, capital expenditures increased by approximately $32.6 million during 2011 as compared to 2010 primarily due to increased spending related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park in 2011 as compared to 2010.
The following table identifies capital expenditures by year:
2010 vs. 2009: Cash used in investing activities was $633.5 million during 2010, which was $102.6 million lower than the same period in 2009 because of lower capital expenditures, lower investments in ATC and higher proceeds from asset sales. During 2010, we received $63 million of proceeds from the sale of Edison Sault.
Financing Activities
The following table summarizes our cash flows from financing activities:
2011 vs. 2010: Cash used in financing activities was $111.3 million during 2011, compared to $172.6 million during 2010. During 2011, we issued a total of $720.0 million of long-term debt and retired $466.6 million of long-term debt. The net proceeds from the new issuance of debt were used to repay short-term debt and for other corporate purposes. For additional information on the debt issuances, see Note J -- Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Financial Statements.
Our common stock dividends increased in 2011 as we raised our dividend rate by 30.0%. In January 2012, our Board of Directors approved an increase of approximately 15.4% in the quarterly common stock dividend.
In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. Funds for the repurchases are expected to come from internally generated funds and working capital supplemented, if required in the short-term, by the sale of commercial paper. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time. Through December 31, 2011, we repurchased approximately 3.2 million shares in the open market pursuant to this program at an average cost of $30.79 per share and a total cost of $100.0 million.
2010 vs. 2009: Cash used in financing activities during 2010 was $172.6 million, compared to $95.7 million of cash provided in 2009. During 2010, we issued a total of $530.0 million of long-term debt and retired $291.7 million of long-term debt. The net proceeds from the new issuance of debt were used to repay short-term debt incurred to finance the construction of OC 1 and for other corporate purposes.
Our common stock dividends increased in 2010 as we raised our dividend rate by 18.5%.
No new shares of Wisconsin Energy's common stock were issued in 2011, 2010 or 2009. During these years, our plan agents purchased, in the open market, 3.0 million shares at a cost of $93.9 million, 5.8 million shares at a cost of $156.6 million and 1.4 million shares at a cost of $29.6 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2011, 2010 and 2009, we received proceeds of $54.4 million, $90.9 million and
$17.0 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 obligations under our dividend reinvestment plan and various employee benefit plans.
CAPITAL RESOURCES AND REQUIREMENTS
Liquidity
We anticipate meeting our capital requirements during 2012 and beyond 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.
We 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.
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.
As of December 31, 2011, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities that were entered into in December 2010. As of December 31, 2011, we had approximately $669.9 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During 2011, our maximum commercial paper outstanding was $717.3 million with a weighted-average interest rate of 0.25%. For additional information regarding our commercial paper balances during 2011, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.
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 as of December 31, 2011:
Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.
The following table shows our capitalization structure as of December 31, 2011 and 2010, 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:
For a summary of the interest rate, maturity and amount outstanding of each series of our long-term debt on a consolidated basis, see the Consolidated Statements of Capitalization.
Included in Long-Term Debt on our Consolidated Balance Sheet as of December 31, 2011 and 2010 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% or greater 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 I -- 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.
Wisconsin Electric is the obligor under two series of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric issued commercial paper to fund the purchase of the bonds. As of December 31, 2011, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.
Bonus Depreciation Provisions
In December 2010, the President of the United States signed tax legislation extending the bonus depreciation rules to certain projects placed in service in 2010, 2011 and 2012. As a result of this extension, we recognized increased federal tax depreciation in 2010 and 2011 relating to assets placed in service during those years, including the Glacier Hills Wind Park, OC 1 and OC 2. In addition, we also anticipate an increase in tax depreciation in 2012 for assets placed in service during 2012, including the Oak Creek AQCS project. As a result of the increased tax depreciation in 2011 and 2012, we will not make federal income tax payments for 2011 and do not anticipate making federal income tax payments for 2012.
Credit Rating Risk
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 in the event of a credit rating change to below BBB- at S&P and/or Baa3 at Moody's. As of December 31, 2011, we estimate that the collateral or the termination payments required under these agreements totaled approximately $184.5 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash. We also have commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.
In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.
In November 2011, Moody's affirmed the ratings of Wisconsin Gas (commercial paper, P-1; senior unsecured, A2). In December 2011, Moody's affirmed the ratings of Wisconsin Energy (commercial paper, P-2; senior unsecured, A3; junior unsecured, Baa1), Wisconsin Electric (commercial paper, P-1; senior unsecured, A2), ERGSS (senior notes, A2) and WECC (senior unsecured, A3). Moody's affirmed the stable ratings outlook assigned to each company.
In June 2011, S&P raised the rating of Wisconsin Energy's junior unsecured debt to BBB from BBB-, and affirmed the ratings of the remaining debt of Wisconsin Energy (commercial paper, A-2; senior unsecured, BBB+), Wisconsin Electric (commercial paper, A-2; senior unsecured, A-), Wisconsin Gas (commercial paper, A-2; senior unsecured, A-) and ERGSS (senior notes, A-). S&P also revised the ratings outlooks assigned to each company from positive to stable in June 2011, after revising the ratings outlooks of each company from stable to positive in March 2011.
In June 2011, Fitch affirmed the ratings of Wisconsin Energy (commercial paper,; senior unsecured, A-; junior unsecured, BBB), Wisconsin Electric (commercial paper,; senior unsecured, A+), Wisconsin Gas (commercial paper,; senior unsecured, A+), ERGSS (senior notes, A+) and WECC (senior unsecured, A-). Fitch also affirmed the stable ratings outlooks assigned to each company.
Subject to other factors affecting the credit markets as a whole, we believe our current 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. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
Capital Requirements
Capital Expenditures: Our estimated 2012, 2013 and 2014 capital expenditures are as follows:
Base spending primarily consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such
as air quality standards, renewable energy standards and electric reliability initiatives that impact our utility energy segment.
Common Stock Matters: During 2012, we expect to continue to repurchase our common stock under the share repurchase program approved by the Board on May 5, 2011, and to pay the increased quarterly dividend of $0.30 per share approved by the Board in January 2012.
Investments in Outside Trusts: We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.5 billion as of December 31, 2011. These trusts hold investments that are subject to the volatility of the stock market and interest rates.
During 2011, we contributed $236.4 million to our qualified pension plans and $41.0 million to our qualified Other Post-Retirement Employee Benefit (OPEB) plans. We did not make contributions to the plans during 2010 as they were adequately funded. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note N -- 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 additional information, see Note G -- Variable Interest Entities and Note O -- Guarantees in the Notes to Consolidated Financial Statements in this report.
Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2011:
(a)
The amounts included in the table are calculated using current market prices, forward curves and other estimates.
(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 Replacement Capital Covenant (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 Point Beach.
(f)
Other Long-Term Liabilities includes the expected 2012 supplemental executive retirement plan obligation. For additional information on employer contributions to our benefit plans, see Note N -- Benefits in the Notes to Consolidated Financial Statements.
The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these 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.
FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES
MARKET RISKS AND OTHER SIGNIFICANT RISKS
We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Regulatory Recovery: Our utility energy segment accounts for its regulated operations in accordance with accounting guidance for regulated entities. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. Regulated entities are allowed 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. We record these items as regulatory liabilities. As of December 31, 2011, our regulatory assets totaled $1,265.7 million and our regulatory liabilities totaled $915.9 million.
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. Effective January 1, 2011, the PSCW implemented new fuel rules which allow for a deferral of prudently incurred fuel costs that fall outside of a symmetrical band (plus or minus 2%). Under the rules, any over or under-collection of fuel costs deferred at the end of the year would be incorporated into fuel cost recovery rates in future years. For information regarding the fuel rules, see Utility Rates and Regulatory Matters -- Wisconsin Fuel Rules.
Natural Gas Costs: 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. Higher natural gas costs may also lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.
As part of its November 2011 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs through December 31, 2012. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds or is less than amounts allowed in rates.
As a result of GCRMs, our gas utility operations receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. For information concerning the natural gas utilities' GCRMs, see Utility Rates and Regulatory Matters.
Weather: Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric's electric revenues and sales 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 and sales 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 2011, 2010 and 2009, 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, 2011. 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 as of December 31, 2011 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2011, we had $669.9 million of commercial paper outstanding with a weighted average interest rate of 0.27% and $147.0 million of variable-rate long-term debt outstanding with a weighted average interest rate of 0.50%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $8.2 million.
Marketable Securities Return: We use various trusts to fund our pension and OPEB obligations. These trusts 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 the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.
The fair value of our trust fund assets as of December 31, 2011 was approximately:
For 2012, the expected long-term rate of return on plan assets is 7.25% and 7.5%, respectively, for the pension and OPEB plans.
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.
We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.
Economic Conditions: Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. We are exposed to market risks in the regional midwest economy.
Inflation: We continue to monitor the impact of inflation, especially with respect to the 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
All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. 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)
Cash costs represent actual and current projected costs, excluding capitalized interest. Approximate costs for OC 1 and OC 2 include the cost of the settlement agreement with Bechtel adjusted for our ownership percentage.
We are recovering our costs in these units through lease payments associated with PWGS 1, PWGS 2 and OC 1 that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the MPSC and FERC. Wisconsin Electric is recovering the lease payments associated with OC 2 as authorized by the PSCW and FERC, and has requested authorization from the MPSC in the rate case filed in July 2011. 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 Oak Creek Units. The interest component of the return has been determined at rates in effect at the time of commercial operation.
Background: The PSCW issued orders granting CPCNs for the construction of the PWGS and the Oak Creek expansion in 2002 and 2003, respectively.
PWGS consists of two natural gas-fired combined cycle generating units on the site of Wisconsin Electric's former Port Washington Power Plant, the natural gas lateral to supply the new plant, and the transmission system upgrades required of ATC. PWGS 1 and PWGS 2 were completed within the PSCW approved cost parameters and were placed in service in July 2005 and May 2008, respectively.
The Oak Creek expansion consists of two coal-fired generating units located adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. OC 1 and OC 2 were placed into service on February 2, 2010 and January 12, 2011, respectively. The PSCW set the total cost for the two units at $2.191 billion. We estimate that the final cost of the Oak Creek expansion is approximately $181 million, or 8.3%, over the amount initially approved by the PSCW, of which our share is approximately $154 million. The additional amount includes the amounts payable to Bechtel pursuant to the Settlement Agreement. The order approving the Oak Creek expansion provides 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 also be included in lease payments and recovered from customers if the PSCW finds that such costs were prudently incurred and were the result of force majeure conditions, an excused event and/or event of loss. In addition, the leases provided for a guaranteed in-service date of September 29, 2009 for OC 1 and September 29, 2010 for OC 2, and imposed liquidated damages of $250,000 per day, of which ERGSS' share is approximately $208,350 per day, for failure to achieve the guaranteed in-service date unless the delays resulted from force majeure conditions or an excused event. In light of the weather delays incurred on the project and other factors, we expect to request authorization from the PSCW to recover all costs associated with the units and to grant relief from liquidated damages.
ERGSS was entitled to receive its share of $250,000 per day from Bechtel under the contract with Bechtel for each day Bechtel failed to achieve the guaranteed in-service dates of September 29, 2009 and September 29, 2010, unless the delays resulted from force majeure conditions or excused events. Pursuant to the terms of the Settlement Agreement and a change order signed concurrent with the turnover of OC 2, Bechtel was granted total schedule relief of 120 days for OC 1 and 81 days for OC 2. Therefore, Bechtel was responsible for 5 days of liquidated damages for OC 1 and 23 days for OC 2. All liquidated damages collected are for the benefit of Wisconsin Electric's customers. Although we anticipate the PSCW will agree that the excused delays were caused by force majeure and other conditions, there is no guarantee that it will grant ERGSS the same schedule relief.
For information regarding the Settlement Agreement, see Oak Creek Construction Contract in Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Lease Terms: The PSCW approved the lease agreements and related documents under which Wisconsin Electric will staff, operate and maintain PWGS 1, PWGS 2, OC 1 and OC 2. Key terms of the leased generation contracts are as follows:
PWGS 1 & PWGS 2
•
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 order, which do not include the key financial terms.
OC 1 & OC 2
•
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;
•
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 order, which do not include the key financial terms.
UTILITY RATES AND REGULATORY MATTERS
The PSCW regulates our retail electric, natural gas and steam rates in the state of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The MPSC regulates our retail electric rates in the state of Michigan. Within our regulated segment, we estimate that approximately 86% of our electric revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam 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/.
2012 Wisconsin Rate Case: On May 26, 2011, Wisconsin Electric and Wisconsin Gas filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which results in no increase in 2012 base rates for our customers. In 2012, Wisconsin Electric and Wisconsin Gas would seek base rate increases to be effective in 2013. In order for us to proceed under this alternative approach, Wisconsin Electric and Wisconsin Gas requested that the PSCW issue an order that:
•
Authorizes Wisconsin Electric to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.
•
Authorizes $148 million of carrying costs and depreciation on previously authorized air quality and renewable energy projects, effective January 1, 2012.
•
Authorizes the refund of $26 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE.
•
Authorizes Wisconsin Electric to reopen the rate proceeding in 2012 to address, for rates effective in 2013, all issues set aside during 2012, including the determination of the final approved construction costs for the Oak Creek expansion.
•
Schedules a proceeding to establish a 2012 fuel cost plan.
On October 6, 2011, the PSCW approved our proposal as filed. We received a final written order from the PSCW on
November 3, 2011. For information related to the proceeding to establish a 2012 fuel cost plan, see 2012 Fuel Recovery Request below. We expect to initiate a traditional rate case filing in early 2012 for new electric, gas and steam rates to be effective in January 2013.
2012 Michigan Rate Case: On July 5, 2011, Wisconsin Electric filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. Therefore, in January 2012, we implemented a $5.7 million interim electric base rate increase. This increase is offset by a refund of $2.7 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE, resulting in a net $3.0 million rate increase. In addition, approximately $2.0 million of renewable costs were included in our Michigan fuel recovery rate effective January 1, 2012. Therefore, the total self-implementation was $7.7 million. A final decision from the MPSC is expected in July 2012.
2010 Wisconsin Rate Case: In March 2009, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric initially asked the PSCW to approve a rate increase for its Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for its natural gas customers of approximately $22.1 million, or 3.6%. In addition, Wisconsin Electric requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for its Milwaukee Downtown (Valley) steam utility customers and Milwaukee County steam utility customers, respectively. Wisconsin Gas asked the PSCW to approve a rate increase for its natural gas customers of approximately $38.9 million, or 4.6%.
In July 2009, Wisconsin Electric filed supplemental testimony with the PSCW updating its rate increase request for retail electric customers to reflect the impact of lower sales as a result of the decline in the economy. The effect of the change resulted in Wisconsin Electric increasing its request from $76.5 million to $126.0 million.
In December 2009, the PSCW authorized rate adjustments related to Wisconsin Electric's and Wisconsin Gas' requests to increase electric, natural gas and steam rates. The PSCW approved the following rate adjustments:
•
An increase of approximately $85.8 million (3.35%) in retail electric rates for Wisconsin Electric, which was partially offset by bill credits in 2010 and included a decrease in base fuel revenues of approximately $111.0 million, or a fuel rate component decrease of 13.8%;
•
A decrease of approximately $2.0 million (0.35%) for natural gas service for Wisconsin Electric;
•
An increase of approximately $5.7 million (0.70%) for natural gas service for Wisconsin Gas; and
•
A decrease of approximately $0.4 million (1.65%) for Wisconsin Electric's Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for its Milwaukee County steam utility customers.
These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered the authorized return on equity for Wisconsin Electric from 10.75% to 10.4% and for Wisconsin Gas from 10.75% to 10.5%.
The PSCW also made, among others, the following determinations:
•
New depreciation rates were incorporated into the new base rates approved in the rate case;
•
Certain regulatory assets that were scheduled to be fully amortized over four years are instead being amortized over eight years; and
•
Wisconsin Electric will continue to receive AFUDC on 100% of Construction Work in Progress for the environmental control projects at our Oak Creek Power Plant and at Edgewater Generating Unit 5, and on the Glacier Hills Wind Park. Wisconsin Electric sold its interest in Edgewater Generating Unit 5 in March 2011 and completed construction of Glacier Hills in December 2011.
As part of its final decision in the 2010 rate case, the PSCW authorized Wisconsin Electric to reopen the docket in 2010 to review updated 2011 fuel costs. On September 3, 2010, Wisconsin Electric filed an application with the PSCW to reopen the docket to review updated 2011 fuel costs and to set rates for 2011 that reflect those costs. Wisconsin Electric requested an increase in 2011 Wisconsin retail electric rates of $38.4 million, or 1.4%, related to the increase in 2011 monitored fuel costs as compared to the level of monitored fuel costs then embedded in rates. In December 2010, Wisconsin Electric reduced its request by approximately $5.2 million. Adjustments by the PSCW reduced the request by an additional $7.8 million. The PSCW issued its final decision, which increased annual Wisconsin retail rates by $25.4 million effective April 29, 2011. The net increase was being driven primarily by an increase in the delivered cost of coal.
2010 Michigan Rate Increase Request: In July 2009, Wisconsin Electric filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In December 2009, the MPSC approved Wisconsin Electric's modified self-implementation plan to increase electric rates in Michigan by approximately $12 million, effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase is $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually, effective November 1, 2010. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In December 2010, the MPSC filed a Motion for Remand with the Court of Appeals. In March 2011, the Court of Appeals denied the Motion for Remand. All briefs have been filed and the case is awaiting scheduling of oral argument, which we expect to occur in the first quarter of 2012.
Limited Rate Adjustment Requests
2012 Fuel Recovery Request: On August 3, 2011, Wisconsin Electric filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase are projected higher coal, coal transportation and purchased power costs. This filing was made under the new Wisconsin fuel rules which require annual fuel cost filings. On January 5, 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer rates.
2010 Fuel Recovery Request: In February 2010, Wisconsin Electric filed a $60.5 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel and purchased power costs was driven primarily by increases in the price of natural gas compared to the forecasted prices included in the 2010 PSCW rate case order, changes in the timing of plant outages and increased MISO costs. Effective March 25, 2010, the PSCW approved an annual increase of $60.5 million in Wisconsin retail electric rates on an interim basis. On April 28, 2011, the PSCW approved the final increase with no changes.
2009 Fuel Order: Under the fuel rules in effect in 2008 and 2009, a Wisconsin utility could request an emergency rate increase if projected costs fell outside of a prescribed range of costs which was plus or minus 2% of the fuel rate approved in a general rate proceeding.
In March 2008, Wisconsin Electric filed a request for an emergency rate increase with the PSCW to recover forecasted increases in fuel and purchased power costs. The PSCW authorized a total increase of $118.9 million. In April 2009, Wisconsin Electric filed a request with the PSCW to decrease annual Wisconsin retail electric rates by $67.2 million because it forecasted that its monitored fuel cost for 2009 would fall outside the range prescribed by the PSCW and would be less than the fuel cost reflected in then authorized rates. The PSCW approved this request on an interim basis with rates effective May 1, 2009.
The PSCW staff audited the fuel costs for the year 2009 to determine whether Wisconsin Electric collected excess revenues as a result of the fuel surcharges that were in place in 2008 and 2009. Under the fuel rules, if a utility collects excess revenues in a year in which it implemented an emergency fuel surcharge, it is required to refund to customers the over-collected fuel surcharge revenue up to the amount of the excess revenues. In February 2011, the PSCW closed out its review of this matter and determined that Wisconsin Electric did not collect any excess revenues.
Other Utility Rate Matters
Oak Creek Air Quality Control System Approval: 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 currently expect the cost of completing this project to be approximately $750 million ($900 million including AFUDC). The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree with the EPA.
Wisconsin Fuel Rules: Embedded within Wisconsin Electric's base rates is an amount to recover fuel costs. New fuel rules adopted in December 2010 require the company to defer, for subsequent rate recovery or refund, any
under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility's approved fuel cost plan. Fuel cost plans approved by the PSCW after January 1, 2011 are subject to the new rules. The deferred fuel costs are subject to an excess revenues test.
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 deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs we deferred at our weighted-average cost of capital. As of December 31, 2011, we had $118.3 million of unrecovered transmission costs. The escrow accounting treatment has been discontinued as our 2008 and 2010 PSCW rate orders have provided for recovery of these costs.
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. As part of its January 2010 rate order, the PSCW approved changes to the GCRMs. The GCRMs now use a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers. The modified one for one is the same method used by the other utilities in Wisconsin.
Depreciation Rates: In January 2009, we filed a depreciation study with the PSCW, proposing new depreciation rates that would reduce annual depreciation expense by approximately $55 million. The PSCW approved the depreciation study and the new depreciation rates began on January 1, 2010. We estimate that the new depreciation rates did not have a material impact on earnings because the new depreciation rates were considered when the PSCW set our 2010 electric and gas rates.
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%. Under Act 141, Wisconsin Electric could not decrease its renewable energy percentage for the years 2006-2009, and for the years 2010-2014, it must increase its renewable energy percentage at least two percentage points to a level of 4.27%. As of December 31, 2011, we are in compliance with the Wisconsin renewable energy percentage 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. To comply with increasing requirements, Wisconsin Electric has constructed and contracted for several hundred megawatts of wind generation and is in the process of constructing approximately 50 MW of biomass fueled generation. With the commercial operation of the Glacier Hills Wind Park in December 2011 and assuming the biomass project is completed on schedule, we expect to be in compliance with Act 141 through the year 2016. To remain in compliance with Act 141, we would need to construct or contract for the equivalent of approximately 400 MW of additional wind generating capacity beyond 2016. See Renewable Energy Portfolio discussion below for additional information regarding the development of renewable energy generation.
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. 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
Wisconsin Department of Administration back to the PSCW and/or contracted third parties. In addition, Act 141 required that 1.5% of utilities' annual operating revenues be used to fund these programs in 2011. The funding required by Act 141 decreased to 1.2% of annual operating revenues in 2012.
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.
Renewable Energy Portfolio: The Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW, commenced commercial operation in May 2008. The Glacier Hills Wind Park, which has 90 turbines with an installed capacity of 162 MW, commenced commercial operation in December 2011. We estimate that the final cost of the Glacier Hills Wind Park will be approximately $355 million.
We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar's sustainable papermaking operations. Construction commenced on June 27, 2011. We currently expect to invest between $245 million and $255 million, excluding AFUDC, in the plant and we expect the plant to be completed during the fall of 2013.
Pursuant to the National Defense Authorization Act (NDAA), which was passed in December 2011, utilities are now able to elect to receive a cash grant for renewable energy projects without the effect of normalization for income tax purposes. We are currently evaluating the impact of the NDAA on whether we pursue federal production tax credits or grants for certain of our renewable generation projects.
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 2011 and 2010. 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 2012. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures.
ENVIRONMENTAL MATTERS
Overview
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting our utility and non-utility energy segments include but are not limited to current and future regulation of: (1) air emissions such as SO2, NOx, fine particulates, mercury and greenhouse gas emissions; (2) water discharges; (3) disposal of coal combustion by-products such as fly ash; and (4) remediation of impacted properties, including former manufactured gas plant sites.
We are continuing to pursue a proactive strategy to manage our environmental compliance obligations, including: (1) developing additional sources of renewable electric energy supply; (2) reviewing water quality matters such as
discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) implementing a Consent Decree with the EPA to reduce emissions of SO2 and NOx by more than 65% by 2013; (5) continuing the beneficial use of ash and other solid products from coal-fired generating units; and (6) conducting the clean-up of former manufactured gas plant sites.
Air Quality
EPA Consent Decree: In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from certain of its coal-fired generating facilities. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. For further information, see Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in southeastern Wisconsin as non-attainment areas for the 8-hour ozone ambient air quality standard. The EPA has since redesignated three of these counties - Kewaunee, Manitowoc and Door - in attainment with the standard, and has made a finding that the remaining seven counties have achieved attainment with the standard. The EPA has stated, however, that Wisconsin must revise a portion of its State Implementation Plan (SIP) relating to volatile organic compounds, which do not apply to our facilities, before these seven counties can be formally redesignated. Pending redesignation, we will continue to be subject to more stringent permitting standards for new or revised facilities in the affected seven counties.
In March 2008, the EPA announced its decision to further lower the 8-hour ozone standard, and in January 2010, the EPA proposed to lower that standard further. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard until 2013, and the EPA began implementing the 2008 standard. The EPA has stated that it plans to finalize the designations under the 2008 ozone standard by May 31, 2012. The EPA has preliminarily designated Waukesha, Washington, Milwaukee and Racine Counties as being in attainment with the standard. Currently, the only counties in Wisconsin that are proposed for non-attainment are Kenosha and Sheboygan Counties.
Fine Particulate Standard: In December 2006, a more restrictive federal standard for fine particulate matter (PM2.5) became effective; however, in February 2009, the U.S. Court of Appeals for the D.C. Circuit issued a decision on the revised standard and remanded it back to the EPA for revision. In October 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the 2006 daily standard for PM2.5. Wisconsin has submitted a request to the EPA to redesignate these three counties as being in attainment with the 2006 standard. If the EPA denies this request, Wisconsin will be required to develop a SIP and submit it to the EPA for approval, and will need to implement actions to reach attainment in the 2014-2019 time period. The impact of future SIP requirements on our operations, if any, cannot be determined at this time, particularly given the EPA's continued efforts to revise the 2006 standard in light of the D.C. Circuit Court's decision.
In a related matter, in August 2010, the Wisconsin Natural Resources Board adopted rules to reflect changes made by the EPA in their regulations regarding the regulation of PM2.5. The rule became effective on January 1, 2011. PM2.5 is proposed to be included as a pollutant used to determine whether a facility is a major source of air pollution. Additionally, any modifications to an existing facility that would result in increases in PM2.5 emissions could trigger pre-construction permitting requirements, including requirements to control emissions to levels which represent best available control technology or lowest achievable emission rate.
Sulfur Dioxide Standard: In June 2010, the EPA issued new hourly SO2 National Ambient Air Quality Standards that became effective in August 2010. These standards, as modified, represent a significant change from the previous SO2 standards. The new standards, among other things, require attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data.
Various parties have submitted judicial and administrative challenges to this rule, and litigation is pending in the U.S. Court of Appeals for the D.C. Circuit challenging, among other things, the stringency of the standards and the EPA's plans to require attainment designations to be based on modeling.
If the new standards remain in place, we believe that we would not need to make significant capital expenditures at the majority of our generation units because of prior investments in pollution control equipment and technology. However, we believe that the new standards may require us to retire our Presque Isle Power Plant in the Upper Peninsula of Michigan early because the cost of installing new pollution control equipment at this plant may exceed other alternatives we are currently studying, which include investing in the transmission system in that region, adding new air quality controls and possible shared ownership of the Presque Isle Power Plant. The new standards may also require us to make modifications at some of our smaller generation units.
Nitrogen Dioxide Standard: In January 2010, the EPA announced a new hourly Nitrogen Dioxide standard, which became effective in April 2010. We are unable to predict the impact on the operation of our coal-fired generation facilities until final attainment designations are made and until any potential additional rules are adopted.
Mercury and Other Hazardous Air Pollutants: On December 16, 2011, the EPA issued the final utility MACT rule (referred to as the MATS rule), which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. While we are continuing to evaluate the impact of the rule on the operation of our existing coal-fired generation facilities, as well as alternatives for complying with the rule, we currently estimate our cost to comply with this rule will be approximately $16 million. Based upon our review, the VAPP and Presque Isle Power Plant may require additional modifications. In addition, we believe that our clean air strategy, including the environmental upgrades that have already been constructed and that are currently under construction at our other plants, positions those plants well to meet the rule's requirements.
Cross-State Air Pollution Rule: On August 8, 2011, the EPA issued a final rule, the Cross-State Air Pollution Rule (CSAPR), formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of NOx and SO2 that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. On October 14, 2011, the EPA published proposed revisions to CSAPR, which if finalized, would delay the implementation date for certain penalty provisions that could potentially impact the Presque Isle Power Plant and increase the number of allowances issued to the states of Michigan and Wisconsin. Even with these proposed revisions, however, the Presque Isle Power Plant may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.
The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and on December 30, 2011, the U.S. Court of Appeals for the District of Columbia granted a motion to stay CSAPR pending judicial review of the rule. While the CSAPR is stayed, the CAIR will remain in effect. We are unable to predict the outcome of this review at this time.
Wisconsin and Michigan Mercury Rules: Both Wisconsin and Michigan have mercury rules that require a 90% reduction of mercury. We have plans in place to comply with those requirements and the costs of these plans are incorporated into our capital and operation and maintenance costs.
Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule (CAVR) in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. The pollutants from power plants that reduce visibility include PM2.5 or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia.
Pursuant to the rule, in July 2011, Wisconsin proposed a draft SIP for public comment. Michigan submitted a complete SIP to the EPA, but on December 30, 2011, the EPA proposed to disapprove the portion of the Michigan SIP that related to utility reductions of NOx and SO2 that were expected to occur under CAIR because the EPA had replaced the CAIR program with CSAPR. In this same proposal, the EPA proposed a partial Federal Implementation Plan (FIP) for Michigan that would rely on CSAPR for utility reductions of NOx and SO2. Issuance of a final partial FIP to Michigan may not occur while judicial review of CSAPR is pending. The EPA did not take action on the other portions of the Michigan SIP submittal.
The BART rules completed by Wisconsin and Michigan, which cover one aspect of the CAVR regulations, are partially based on utility reductions of NOx and SO2 that were expected to occur under CAIR. While the EPA has
expressed its intention to allow states to consider utility reductions of NOx and SO2 expected under CSAPR in its Regional Haze SIPs, we will not be able to determine final impacts of these rules until judicial review of CSAPR is completed and any subsequent rulemaking activities required as result of that review have been finalized.
Climate Change: 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 an 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:
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Repowering the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
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Adding coal-fired units as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.
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Increasing investment in energy efficiency and conservation.
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Adding renewable capacity and promoting increased participation in the Energy for Tomorrow® renewable energy program.
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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. The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our CO2 emissions that may be adopted by Congress or Wisconsin's or Michigan's legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition. While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. These regulations are expected to impact our ability to do maintenance or modify our existing facilities, and permit new facilities. Depending on the extent of rate recovery and other factors, these rules could have a material adverse impact on our 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.
Beginning with 2010, we are required to report our CO2 equivalent emissions from our electric generating facilities to the EPA under its Mandatory Reporting of Greenhouse Gases rule. For 2010, we reported CO2 equivalent emissions of approximately 20.9 million metric tonnes to the EPA. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO2 equivalent emissions of approximately 22.6 million metric tonnes to the EPA for 2011. The level of CO2 and other greenhouse gas emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed and how our units are dispatched by MISO.
We are also required to report CO2 amounts related to the natural gas our gas utility distributes and sells. For 2010, we reported approximately 9.0 million metric tonnes of CO2 to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO2 emissions of approximately 9.6 million metric tonnes to the EPA for 2011.
Valley Power Plant: We are exploring various options at VAPP in connection with the new environmental regulations, including converting it from a coal-fired plant to a natural gas-fired plant. For further information, see Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Water Quality
Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. Final rules for cooling water intake systems at existing facilities (Phase II) were promulgated in 2004. However, as a result of litigation, the EPA withdrew the Phase II rule in July 2007 and advised states to use their best professional judgment in making BTA decisions while the rule remains suspended.
The EPA proposed a new Phase II rule on March 28, 2011, which must be finalized by July 27, 2012 in accordance with a judicial settlement entered into by the EPA. Once the rule is final, it will apply to all of our existing generating facilities with cooling water intake structures other than the Oak Creek expansion, which was permitted under the Phase I rules.
The proposed rule would create an impingement mortality reduction standard for all existing facilities. One proposed approach would allow a facility owner to satisfy the BTA requirement with respect to impingement mortality reduction if it demonstrates that its cooling water intake system has a maximum intake velocity of no more than 0.5 feet per second. Oak Creek Power Plant Units 5-8, Pleasant Prairie and Port Washington Generating Station all employ technologies that have a cooling water intake withdrawal velocity of less than 0.5 feet per second. We are still evaluating impingement mortality reduction compliance options for the Presque Isle Power Plant and VAPP.
The EPA has proposed that the BTA for entrainment mortality reduction be determined on a case-by-case basis. Therefore, permitting agencies would be required to determine BTA with respect to entrainment on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet this proposed requirement.
Depending on the final requirements of the Phase II rule, we may need to modify the cooling water intake systems at some of our facilities. However, we are not able to make a determination until after the Phase II rule is final.
Steam Electric Effluent Guidelines: The federal Steam Electric Effluent guidelines, which regulate waste water discharges, are under review by the EPA. These rules govern discharges of waste water from our power plant processes. The EPA rules are expected to be finalized in 2014. After the promulgation of final rules, it is expected that the WDNR will need to modify Wisconsin's rules. The existing Wisconsin state rules for waste water discharge are very stringent, and therefore, the systems that have been installed at the Pleasant Prairie Power Plant and the Oak Creek Power Plant use advanced technology. We are unable to determine the impact, if any, of these rules on our facilities at this time.
Land Quality
Proposed New Coal Combustion Products Regulation: We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In June 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products. One of the proposed rules classifies the materials as hazardous waste. We submitted comments on the proposed rules in November 2010. The EPA also issued a NODA in October 2011, and we submitted comments on the NODA in November 2011. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.
If coal combustion products are classified as hazardous waste and we terminate our coal combustion products utilization program, we could be required to dispose of the coal combustion products at a significant cost to the Company, which could adversely impact our results of operations and financial condition.
In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the CAA, and finalized a Non-Hazardous Secondary Materials Rule. Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills. Presently, we have a successful program for reburning coal ash to recover energy and produce a usable fly ash product for the concrete industry.
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 R -- 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 R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
LEGAL MATTERS
Cash Balance Pension Plan: In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of the Employee Retirement Income Security Act of 1974 (ERISA) and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.
In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $0.04 per share for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.
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.
Dairy farmers continue to make claims against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage and 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 these rulings, 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. This lawsuit was settled in May 2011. This settlement did not have a material effect on our financial condition or results of operations. Another stray voltage lawsuit was filed against Wisconsin Electric in January 2011, but was dismissed without prejudice by the court on February 21, 2012. We continue to evaluate various options and strategies to mitigate this risk.
NUCLEAR OPERATIONS
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 United States Nuclear Regulatory Commission 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. In December 2009, the Court ruled in favor of Wisconsin Electric, granting us more than $50 million in damages. In February 2010, the DOE filed an appeal. We negotiated a settlement with the DOE for $45.5 million, which we received in the first quarter of 2011. This amount, net of costs incurred, is being returned to customers as part of the PSCW's approval of our 2012 fuel recovery request and the MPSC's approval of our interim order for the 2012 Michigan rate case.
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.
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.
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 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 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 an ancillary services market. 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 has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.
In MISO, base transmission costs are currently being paid by Load Serving Entities located in the service territories of each MISO transmission owner. FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.
In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee (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. In July 2007, MISO commenced with the resettlement of the market in response to the orders. 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 ordered 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. Although MISO requested a postponement of the resettlements until the matter is resolved, the resettlement commenced in March 2009. In May 2009, FERC issued an order denying rehearing on substantive matters for the rate period beginning August 10, 2007. However, FERC modified the effective date of that rate to November 10, 2008, and ordered MISO to cease the ongoing resettlement and to reconcile all invoices and payments therein. Similarly, in June 2009, FERC dismissed rehearing requests, but waived refunds for the period April 25, 2006 through November 4, 2007. FERC also stated for the first time that it was waiving refunds for the period April 1, 2005 through April 24, 2006. We, along with others, have sought rehearing and/or appeal of the FERC's May and June 2009 determinations pertaining to refunds. In addition, there are contested compliance matters pending FERC review. The net effects of FERC's rulings are uncertain at this time.
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 Auction Revenue Rights (ARRs) and Financial Transmission Rights (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, 2011 through May 31, 2012. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.
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.
International Financial Reporting Standards: During 2009, the SEC announced a "roadmap" for the potential use by U.S. registrants of IFRS instead of GAAP. The SEC issued a Work Plan to consider specific areas and factors relevant to a determination of whether, when and how the current financial reporting system for U.S. registrants should be transitioned to a system incorporating IFRS. Working under the assumption that the SEC would make a decision in 2011, the Work Plan anticipated that the first time U.S. registrants would report under IFRS would be approximately 2015 or 2016. Since the release of the Work Plan, the SEC has issued several papers discussing the incorporation of IFRS into the U.S. financial reporting system and held a roundtable discussion, but has yet to make a determination regarding IFRS. To the extent the SEC determines to adopt IFRS, if at all, we are currently unable to determine when we would be required to begin using IFRS.
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. The actions of our regulators may allow us to defer costs that non-regulated entities would expense and accrue liabilities that non-regulated companies would not. As of December 31, 2011, we had $1,265.7 million in regulatory assets and $915.9 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 regulatory accounting. In this situation, we would record the regulatory assets related to unrecognized pension and OPEB costs as a reduction of equity, after tax. The balance of our regulatory assets net of regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. We continually review the applicability of regulatory accounting and have determined that it is currently appropriate to continue following it. 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 N -- 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.
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 table reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.
Pension Plan
Impact on
Actuarial Assumption
Annual Cost
(Millions of Dollars)
0.5% decrease in discount rate and lump sum conversion rate
$4.7
0.5% decrease in expected rate of return on plan assets
$5.7
In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N -- Benefits in the Notes to Consolidated Financial Statements). 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 accounting guidance for compensation related to retirement benefits for rate-making purposes.
The following table 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 2011 of approximately $4.4 billion included accrued utility revenues of $252.7 million as of December 31, 2011.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Item 7 of this report, as well as Note L -- Derivative Instruments and Note M -- Fair Value Measurements in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Variable interest rate as of December 31, 2011.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
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 and Wisconsin Gas, 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 includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions and balances within this segment from the consolidated financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications: Certain prior period amounts have been reclassified on a basis consistent with the current period financial statement presentation.
On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information has been restated for all periods presented to reflect this stock split.
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. Beginning in January 2011, the electric fuel rules in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred amounts are subject to an excess revenues test.
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 We Power, see Note E.
Accounting for MISO Energy Transactions: 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 recorded 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 2.8% in 2011 and 2010, and 3.7% in 2009.
PWGS 1, PWGS 2, OC 1 and OC 2 are being depreciated over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.
Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We 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 $728.2 million as of December 31, 2011 and $723.9 million as of December 31, 2010.
We recorded the following Construction Work in Progress (CWIP) by segment as of 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 2009, Wisconsin Electric accrued AFUDC at a rate of 9.09% as authorized by the PSCW. Consistent with the PSCW's 2008 rate order, Wisconsin Electric accrued AFUDC on 50% of all utility CWIP projects except the Oak Creek AQCS project, which accrued AFUDC on 100% of CWIP. Wisconsin Electric's rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Electric recorded AFUDC on 100% of CWIP associated with the Oak Creek AQCS project, the Edgewater Unit 5 Selective Catalytic Reduction project and the Glacier Hills Wind Park. Wisconsin Electric recorded AFUDC on 50% of all other electric, gas and steam utility CWIP. The AFUDC rate starting January 1, 2010 was 8.83%. This AFUDC accrual policy and rate for Wisconsin Electric continued through 2011 and will continue through 2012.
Wisconsin Electric is also accruing AFUDC on 100% of the biomass project.
During 2009, Wisconsin Gas accrued AFUDC at a rate of 10.80% on 50% of its CWIP as authorized by the PSCW in its 2008 rate order. Wisconsin Gas' rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Gas recorded AFUDC on 50% of all CWIP using an AFUDC rate of 9.05%. This AFUDC accrual policy and rate for Wisconsin Gas continued through 2011 and will continue through 2012.
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 PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms. 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 attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. 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 excluded from the calculation. All stock options outstanding during 2011 were included in the computation of diluted earnings per share. For 2010 and 2009, the calculation of diluted earnings per share excluded an immaterial number of out-of-the money stock options that had an anti-dilutive effect.
Materials, Supplies and Inventories: Our inventory as of December 31 consists of:
Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
Regulatory Accounting: 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 regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. 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: 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 regulatory accounting guidance 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. For further information, see Note F.
Derivative Financial Instruments: We have derivative physical and financial instruments which we report at fair value. For further information, see Note L.
Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
Restricted Cash: For 2011, restricted cash consists of the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. For 2010, restricted cash consisted of cash proceeds that we received from the sale of Point Beach that were used for the benefit of our customers. As of December 31, 2011, all restricted cash is classified as current.
Margin Accounts: Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.
Goodwill: Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2011 and 2010, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.
Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed 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 as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2011 impairment test date.
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, 2011, we had no assets classified as Held for Sale. 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.
Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 26.2% in ATC as of December 31, 2011 and 2010. 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 Q.
Income Taxes: We follow the liability method in accounting for income taxes. Accounting guidance for income taxes 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. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those 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: We estimate the fair value of stock options using the binomial pricing model. 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 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 10 years from grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note I.
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
Presentation of Comprehensive Income: In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of changes in stockholders' equity. The guidance gives entities the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued an amendment to indefinitely defer one of the requirements contained in its June 2011 final standard. That requirement called for reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income. This guidance, including the related deferral, is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We are currently assessing the effects this guidance may have on our consolidated financial statements.
Fair Value Measurement: In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. Under the new guidance, required disclosures are expanded, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities will also be required to disclose the categorization, by level of the fair value hierarchy, of items that are not measured at fair value in the balance sheets but for which the fair value is required to be disclosed. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We are currently assessing the effects this guidance may have on our consolidated financial statements.
C -- REGULATORY ASSETS AND LIABILITIES
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 regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2011 and 2010, we had approximately $11.0 million and $16.5 million, respectively, of net regulatory assets that were not earning a return. These regulatory assets are expected to be recovered from customers over a period of one to five years.
In December 2009, the PSCW issued a rate order effective January 1, 2010 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below. The rate order provided for the recovery over an eight year period of specific regulatory assets, the largest of which is the balance of the remaining deferred transmission costs. The order also specified that the deferred Point Beach gain would be passed on to customers as authorized in the prior rate case such that the final credits were issued by the end of 2010.
Our regulatory assets and liabilities as of December 31 consist of:
Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet.
D -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS
Edison Sault: Effective May 4, 2010, we sold Edison Sault Electric Company (Edison Sault) to Cloverland Electric Cooperative for approximately $63.0 million. We reclassified the operations related to Edison Sault as discontinued operations in the accompanying Consolidated Income Statements. Discontinued Edison Sault operations had no significant impact on our Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009. We retained Edison Sault's ownership interest in ATC.
Water Utility Operations: Effective April 30, 2009, we sold our water utility to the City of Mequon, Wisconsin for approximately $14.5 million. We reclassified the water utility income as discontinued operations in the accompanying Consolidated Income Statements. Discontinued water operations had no material impact on the Consolidated Statement of Cash Flows for the year ended December 31, 2009.
The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:
(a)
Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.
Edgewater Generating Unit 5: On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.
E -- ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS
Background: As part of our PTF strategy, our non-utility subsidiary, We Power, built four new generating units, PWGS 1, PWGS 2, OC 1 and OC 2, which are leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW. The leases are designed to recover the capital costs of the plant, including a return. PWGS 1, PWGS 2, OC 1 and OC 2 were placed in service in July 2005, May 2008, February 2010 and January 2011, respectively. 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.
The Oak Creek expansion includes common projects that 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, which were placed in service in November 2007 and January 2009, respectively.
During Construction: Under the terms of each lease, we collected in then current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our PTF units. Our pre-tax cost of capital was approximately 14%. The carrying costs that we collected in rates were recorded as deferred revenue and are amortized to revenue over the term of each lease. During the construction of our PTF units, we capitalized interest costs at an overall weighted-average pre-tax cost of interest, which was approximately 5% for the year ended December 31, 2010. Capitalized interest is included in the total cost of the PTF units.
Plant in Service: Now that the PTF units are in service, we expect to continue 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 were established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs were 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 under each lease was established at rates determined in accordance with the terms of each lease.
We recognize revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease. We depreciate the PTF assets over their estimated useful life.
F -- ASSET RETIREMENT OBLIGATIONS
The following table presents the change in our AROs during 2011 and 2010:
G -- VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interest entities.
We assess our relationships with 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. In making this assessment, 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 which represent variable interests. We account for one of these agreements, with an independent power producer, as an operating lease. The agreement has a remaining term of approximately one and a half years. We have examined the risks of the entity including the impact of operations and maintenance, dispatch, financing, fuel costs, remaining useful life and other factors, and have determined that we are not the primary beneficiary of this entity. We have concluded that we do not have the power to direct the activities that would most significantly affect the economic performance of the entity over its remaining life.
We also have a purchased power agreement for 236 MW of firm capacity from a gas-fired cogeneration facility, which we account for as a capital lease. The agreement includes no minimum energy requirements over the remaining term of 11 years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.
We have approximately $309.5 million of required payments over the remaining term of these agreements. We believe that the required lease payments under these contracts will continue to be recoverable in rates. Total capacity and lease payments under these contracts in 2011, 2010 and 2009 were $65.9 million, $64.2 million and $62.2 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.
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 deferred income taxes classified as net current assets and net long-term liabilities as of December 31 are as follows:
Consistent with rate-making treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.
As of December 31, 2011, we had approximately $867.1 million and $25.0 million of net operating loss and tax credit carryforwards, respectively. The net operating loss and tax credit carryforwards resulted in deferred tax assets of $303.5 million and $25.0 million, respectively, as of December 31, 2011. The tax credit and net operating loss carryforwards begin to expire in 2029 and 2030, respectively. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.
On January 1, 2007, we adopted accounting guidance related to uncertainty in income taxes. 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, 2011 and 2010 excludes deferred tax assets related to uncertainty in income taxes of $11.0 million and $16.9 million, respectively. As of December 31, 2011 and 2010, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $0.1 million and $2.3 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, 2011, 2010 and 2009, we recognized approximately $0.7 million, $4.1 million and $2.0 million, respectively, of accrued interest in the Consolidated Income Statements. For the year ended December 31, 2011, we recognized a benefit of $0.3 million in the Consolidated Income Statements related to a reduction of accrued penalties. For the years ended December 31, 2010 and 2009, we recognized no penalties in the Consolidated Income Statements. We had approximately $2.0 million and $8.2 million of interest accrued and zero and approximately $0.3 million of penalties accrued on the Consolidated Balance Sheets as of December 31, 2011 and 2010, respectively.
We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.
Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2007 through 2011 are subject to Federal and Wisconsin examination.
I -- COMMON EQUITY
As of December 31, 2011 and 2010, we had 325,000,000 shares of common stock authorized under our charter, of which 230,486,804 and 233,771,194 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. We utilize the straight-line attribution method for recognizing share-based compensation expense. 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 other than necessary adjustments as a result of our stock split.
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.
We expect that substantially all of the outstanding options as of December 31, 2011 will be exercised.
The following is a summary of our stock option activity during 2011:
In January 2012, the Compensation Committee awarded 938,770 non-qualified stock options with an exercise price of $34.88 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, 2011, 2010 and 2009 was $36.1 million, $62.1 million and $12.0 million, respectively. Cash received from options exercised during the years ended December 31, 2011, 2010 and 2009 was $54.4 million, $90.9 million and $17.0 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.3 million, $24.1 million and $4.8 million, respectively.
The following table summarizes information about stock options outstanding as of December 31, 2011:
The following table summarizes information about our non-vested options during 2011:
As of December 31, 2011, total compensation costs related to non-vested stock options not yet recognized was approximately $0.6 million, which is expected to be recognized over the next 19 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 2011:
Recipients of previously issued restricted shares have the right to vote the shares and receive dividends, and the shares have vesting periods ranging up to 10 years.
In January 2012, the Compensation Committee awarded 94,959 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.
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. The intrinsic value of restricted stock vesting was $2.5 million, $2.3 million and $0.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.8 million, $0.7 million and $0.3 million, respectively.
As of December 31, 2011, total compensation cost related to restricted stock not yet recognized was approximately $2.4 million, which is expected to be recognized over the next 20 months on a weighted-average basis.
Performance Units: In January 2011, 2010 and 2009, the Compensation Committee awarded 435,690, 555,830 and 666,440 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that 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 unit 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 awards. Performance units earned as of December 31, 2011, 2010 and 2009 vested and were settled during the first quarter of 2012, 2011 and 2010 and had a total intrinsic value of $26.7 million, $12.6 million and $9.8 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $9.7 million, $4.3 million and $3.4 million, respectively.
In January 2012, the Compensation Committee awarded 346,570 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
As of December 31, 2011, total compensation cost related to performance units not yet recognized was approximately $18.3 million, which is expected to be recognized over the next 19 months on a weighted-average basis.
Restrictions: Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our 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 2010 PSCW rate case order requires Wisconsin Electric and Wisconsin Gas to maintain capital structures that 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 required 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, 2011, 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 $3.5 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2011.
See Note K 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.
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 2011, 2010 or 2009.
During 2011, 2010 and 2009, our plan agents purchased 3.0 million shares at a cost of $93.9 million, 5.8 million shares at a cost of $156.6 million and 1.4 million shares at a cost of $29.6 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2011, 2010 and 2009, we received proceeds of $54.4 million, $90.9 million and $17.0 million, respectively, related to the exercise of stock options.
In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time. Through December 31, 2011, we repurchased approximately 3.2 million shares pursuant to this program at an average cost of $30.79 per share and a total cost of $100.0 million.
J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
Debentures and Notes: As of December 31, 2011, 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.
In September 2011, Wisconsin Electric issued $300 million of 2.95% Debentures due September 15, 2021. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011. The net proceeds were used to repay short-term debt and for other general corporate purposes.
On April 1, 2011, we used cash and short-term borrowings to retire $450 million of long-term debt that matured.
In January 2011, we issued a total of $420 million in long-term debt ($205 million aggregate principal amount of 4.673% Series B Senior Notes due January 19, 2031 and $215 million aggregate principal amount of 5.848% Series B Senior Notes due January 19, 2041) and used the net proceeds to repay short-term debt incurred to finance the construction of OC 2 and for other corporate purposes. The Series B Senior Notes are secured by a collateral assignment of the leases between Elm Road Generating Station Supercritical, LLC (ERGSS) and Wisconsin Electric related to OC 2.
In February 2010, we issued a total of $530 million in long-term debt ($255 million aggregate principal amount of 5.209% Series A Senior Notes due February 11, 2030 and $275 million aggregate principal amount of 6.09% Series A Senior Notes due February 11, 2040) and used the net proceeds to repay debt incurred to finance the construction of OC 1. The Series A Senior Notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1.
During 2010, we retired $281.5 million of unsecured notes through the issuance of long-term and short-term debt.
During 2009, we issued $261.5 million of long-term debt, including $250 million of debentures under an existing shelf registration statement filed by Wisconsin Electric with the SEC in August 2007. The net proceeds were used to repay short-term debt and for other general corporate purposes.
Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2011 and 2010, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.
In connection with our outstanding 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 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.
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 $31.3 million and $30.2 million in lease payments during 2011 and 2010, 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, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $132.4 million as of December 31, 2011, and will decrease to zero over the remaining life of the contract.
The 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, 2011 are as follows:
K -- 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 commercial paper for the years ended December 31:
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into 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.
As of December 31, 2011, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and approximately $669.9 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facilities expire in December 2013.
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 several of the covenants contained therein.
As of December 31, 2011, we were in compliance with all financial covenants.
L -- DERIVATIVE INSTRUMENTS
We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW.
We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, 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, 2011, we recognized $29.6 million in regulatory assets and $21.7 million in regulatory liabilities related to derivatives in comparison to $22.0 million in regulatory assets and $15.3 million in regulatory liabilities as
of December 31, 2010.
We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $2.5 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.7 million is recorded in other long-term liabilities. Our Consolidated Balance Sheets as of December 31, 2011 and 2010 include:
Our Consolidated Income Statements include gains (losses) on derivative instruments used in our risk management strategies under fuel and purchased power for those commodities supporting our electric operations and under cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) for the years ended December 31 were as follows:
As of December 31, 2011 and 2010, we posted collateral of $11.9 million and $11.7 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.
For the year ended December 31, 2011, we reclassified $0.2 million and for the years ended December 31, 2010 and 2009, we reclassified $0.4 million 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, $0.1 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.
M -- FAIR VALUE MEASUREMENTS
Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.
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 gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
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 on-going 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 fair value reporting 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 tables summarize our financial assets and liabilities by level within the fair value hierarchy:
Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents (i) for 2010, the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach, and (ii) for 2011, the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. 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 changes to derivatives classified as Level 3 in the fair value hierarchy:
Derivative instruments reflected in Level 3 of the hierarchy include MISO FTRs 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. See Note L -- 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 and unamortized discount on debt, 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.
N -- 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 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:
As of December 31, 2011, our qualified pension plans were over-funded by $24.4 million and our non-qualified pension plans were under-funded by $92.5 million. As of December 31, 2010, our qualified and non-qualified pension plans were under-funded by $71.7 million and $91.6 million, respectively.
Amounts recognized in our Consolidated Balance Sheets as of December 31 related to the funded status of the benefit plans consisted of:
The accumulated benefit obligation for all defined benefit plans was $1,329.4 million and $1,222.5 million as of December 31, 2011 and 2010, 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:
We estimate that 2012 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs referred to above of $43.9 million and $5.5 million, respectively.
The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:
In addition to the costs above, in 2011 we recorded net pension costs of less than $0.04 per share related to the settlement of pension litigation. See Note R -- Commitments and Contingencies in this report. The charges were after considering insurance and reserves established in the prior year.
The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2011 and 2010. The expected long-term rate of return for all plan assets was 8.25% in 2009. We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the 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.
Plan Assets: Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.
The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.
Our current pension plan target asset allocation is 45% equity investments and 55% fixed income investments. The current OPEB target asset allocation is 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.
The following table summarizes the fair value of our pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):
(a)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
The following table summarizes the fair value of our OPEB plan assets by asset category within the fair value hierarchy:
(a)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
Cash Flows:
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 $14.1 million, $13.8 million and $14.1 million during 2011, 2010 and 2009, respectively.
Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $15.3 million as of December 31, 2011.
O -- GUARANTEES
We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2011, we had the following guarantees:
We provide guarantees to support obligations of our affiliates to third parties under 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.
P -- SEGMENT REPORTING
Our operating segments as of December 31, 2011 include a utility energy segment and a non-utility energy segment. We have organized our operating segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. 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 operating segments for each of the three years ended December 31, 2011 is shown in the following table. The segment information below includes income from discontinued operations as a result of the sale of Edison Sault in May 2010 and the water utility in April 2009.
(a)
Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.
(b)
An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.
(c)
An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.
Q -- 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, 2011, 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 the new generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service. As of December 31, 2011 and 2010, we had a receivable of $5.4 million and $3.8 million, respectively, for these items. During the years ended December 31, 2011, 2010 and 2009, our equity in earnings from ATC was $62.5 million, $60.1 million and $59.1 million, respectively. During the years ended December 31, 2011, 2010 and 2009, distributions received from ATC were $49.7 million, $49.3 million and $46.6 million, respectively.
We provided and received services from the following associated companies during 2011, 2010 and 2009:
As of December 31, 2011 and 2010, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:
R -- COMMITMENTS AND CONTINGENCIES
Capital Expenditures: We have made certain commitments in connection with 2012 capital expenditures. During 2012, we estimate that total capital expenditures will be approximately $740.2 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 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases including leases for 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. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5. We have established reserves as deemed appropriate for these indemnification provisions.
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 combustion product disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product 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 on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $21 million to $65 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, 2011, we have established reserves of $37.5 million related to future remediation costs.
Historically, 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.
Coal Combustion Product Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. 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. During 2011, 2010 and 2009, Wisconsin Electric incurred $0.2 million, $0.4 million and $0.3 million respectively, in landfill remediation expenses. As of December 31, 2011, we have no reserves established related to coal combustion product landfill sites.
EPA - Consent Decree: In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. 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, 2011, we have spent approximately $1.0 billion associated with the installation of air quality controls and have retired four coal units as part of our plan under the Consent Decree. The total cost of implementing this agreement is currently estimated to be approximately $1.1 billion over the ten year period ending 2013.
Valley Power Plant Title V Air Permit: The WDNR issued a renewed Title V operating permit for VAPP on February 28, 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested a contested case hearing on certain conditions of the permit, and that request was granted. The Sierra Club also filed a petition requesting that the EPA remand the permit to the WDNR to require lower emission limits for particulate matter, SO2 and NOx, and to revise certain record-keeping requirements. No timeline has been set by the EPA to respond to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards.
The Company filed an application with the PSCW on December 9, 2011 for authority to replace and upgrade the Lincoln Arthur natural gas main, which would also have the capability to accommodate the increased natural gas required if VAPP were to convert from coal to natural gas in the future. We also submitted a letter to the EPA on December 8, 2011 with four voluntary goals, which included: (1) reduce annual SO2 emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) install a dry sorbent injection system at VAPP that is needed to meet the utility MACT rules earlier than the rules require if the installation would provide a direct economic benefit to customers and is approved by the PSCW; (3) hold an open house and tour of VAPP in 2012 to help inform the community on the plant, the unique role that it plays in the community, and to share environmental successes and future plans; and (4) convert VAPP to natural gas fuel by the 2017/2018 timeframe, provided we can demonstrate a direct economic benefit to customers and obtain authorization from the PSCW.
Oak Creek Construction Contract: Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, submitted claims to us on December 22, 2008 for cost and schedule relief related to the delay of the in-service dates for OC 1 and OC 2. These claims were asserted against Elm Road Services, LLC (ERS), the project
manager for the construction of the Oak Creek expansion and agent for the joint owners of OC 1 and OC 2. On October 30, 2009, Bechtel amended its claim to increase its request for cost relief and schedule relief. In its amended claim, Bechtel requested cost relief totaling approximately $517.5 million and schedule relief that would have resulted in approximately seven months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2009 for OC 1 and approximately four months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2010 for OC 2.
Bechtel's first claim was based on the alleged impact of severe weather and certain labor-related matters. Pursuant to its amended claim, Bechtel was requesting approximately $445.5 million in costs related to changed weather and labor conditions. Bechtel's second claim of approximately $72 million sought cost and schedule relief for the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the Full Notice to Proceed in July 2005. These claims, as well as claims submitted by ERS related to the rights of the parties under the construction contract and ERS counterclaims, had been submitted to binding arbitration.
Effective December 16, 2009, ERS and Bechtel entered into the Settlement Agreement that settled the claims between them regarding OC 1 and OC 2. Pursuant to the terms of this Settlement Agreement, ERS will pay to Bechtel $72 million to settle these claims payable upon the achievement of specific project milestones. As of December 31, 2011, Bechtel has received $67 million of the $72 million total settlement. The remaining milestone payments are tied to final acceptance of the units. In addition, Bechtel received 120 days of schedule relief for OC 1 and 60 days for OC 2. Therefore, the guaranteed in-service date of September 29, 2009 for OC 1 was extended to January 27, 2010, and the guaranteed in-service date of September 29, 2010 for OC 2 was extended to November 28, 2010. Bechtel subsequently received an additional 21 days of schedule relief for OC 2 as part of a change order signed concurrent with the turnover of OC 2. Therefore, the total schedule relief granted to Bechtel was 120 days for OC 1 and 81 days for OC 2.
We are responsible for approximately 85% of amounts paid under the Settlement Agreement, consistent with our ownership share of the Oak Creek expansion. The other joint owners are responsible for the remainder.
Cash Balance Pension Plan: In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.
In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $0.04 per share for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.
S -- SUPPLEMENTAL CASH FLOW INFORMATION
During the year ended December 31, 2011, we paid $234.0 million in interest, net of amounts capitalized, and received $109.1 million in net refunds from income taxes. During the year ended December 31, 2010, we paid $198.0 million in interest, net of amounts capitalized, and $166.7 million in income taxes, net of refunds. During the year ended December 31, 2009, we paid $152.3 million in interest, net of amounts capitalized, and received $27.9 million in net refunds from income taxes.
As of December 31, 2011, 2010 and 2009, the amount of accounts payable related to capital expenditures was $16.7 million, $18.2 million and $14.7 million, respectively.
During the years ended December 31, 2011, 2010 and 2009, total amortization of deferred revenue was $54.4 million, $34.6 million and $8.0 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, 2011 and 2010, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 28, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Milwaukee, Wisconsin
February 28, 2012
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, 2011, based on the 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, 2011, 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, 2011 of the Company and our report dated February 28, 2012 expressed an unqualified opinion on those financial statements and financial statement schedules.
/s/DELOITTE & TOUCHE LLP
Milwaukee, Wisconsin
February 28, 2012
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 principal executive officer and principal 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 Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal 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 principal executive officer and principal 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, 2011.
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, 2011. 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 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
As we previously disclosed, James C. Fleming, Executive Vice President and General Counsel of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas, is retiring effective April 1, 2012. In connection with his retirement and in light of his many contributions to our success, on February 24, 2012, the Compensation Committee accelerated the vesting of all unvested shares of restricted stock awarded to Mr. Fleming, consisting of 5,825 shares, effective March 30, 2012.
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 2013", "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 3, 2012 (the "2012 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", "Compensation Committee Report", "Risk Analysis of Compensation Policies and Practices" and "Certain Relationships and Related Transactions - Compensation Committee Interlocks and Insider Participation" in the 2012 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 2012 Annual Meeting Proxy Statement.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information about our equity compensation plans as of December 31, 2011:
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", "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: Does the Company have policies and procedures in place to review and approve related party transactions?" and "Certain Relationships and Related Transactions" in the 2012 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 2012 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
2.
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
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 non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2011, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $272.6 million of dividends and distributions. We Power also provided Wisconsin Energy with $722.2 million of distributions during 2011, which includes the net proceeds from the issuance of $420 million of long-term debt in January 2011.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company 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 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, 2011, 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.
During 2011, Wisconsin Energy used cash and short-term borrowings to retire $450 million of long-term debt that matured.
During 2010, Wisconsin Energy used cash and short-term borrowings to retire $281.5 million of unsecured notes.
During 2009, Wisconsin Energy issued $11.5 million of new notes and used the proceeds to repay short-term debt.
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 several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.
As of December 31, 2011, Wisconsin Energy was in compliance with all covenants.
WECC is a subsidiary of Wisconsin Energy and has $80 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.
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, 2011, Wisconsin Energy had the following guarantees:
Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and agreements.
Wisconsin Energy's guarantees in support of its non-utility energy segment guaranty performance and payment obligations of We Power. The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.
Wisconsin Energy has a guarantee that supports an environmental indemnification obligation, 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. 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 long-term debt, including the current portion of long-term debt, and unamortized discount on debt, 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 Parent Company's bond rating and the present value of future cash flows.
6. During the year ended December 31, 2011, Wisconsin Energy paid $57.7 million in interest, net of amounts capitalized, and received $114.6 million in refunds from income taxes. During the year ended December 31, 2010, Wisconsin Energy paid $43.5 million in interest, net of amounts capitalized, and received $1.0 million in refunds from income taxes. During the year ended December 31, 2009, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $36.0 million in refunds from income taxes.
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 28, 2012
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.
WISCONSIN ENERGY CORPORATION
(Commission File No. 001-09057)
EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 2011
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-1
Wisconsin Energy Corporation
E-2
Wisconsin Energy Corporation
E-3
Wisconsin Energy Corporation
E-4
Wisconsin Energy Corporation
E-5
Wisconsin Energy Corporation
E-6
Wisconsin Energy Corporation
E-7
Wisconsin Energy Corporation