Wisconsin Energy 10-Q 2010
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
For the Quarterly Period Ended September 30, 2010
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Large accelerated filer [X] Accelerated filer [ ]
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Certain statements contained in this report are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, on-going legal proceedings, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "should" or similar terms or variations of these terms.
Actual results may differ materially from those set forth in forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Wisconsin Energy Corporation is a diversified holding company which conducts its operations primarily in two operating segments: 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 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, which serves electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metropolitan Milwaukee, Wisconsin; and Wisconsin Gas, which serves gas customers in Wisconsin. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies."
Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric the new generating capacity included in our PTF strategy. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Annual Report on Form 10-K for more information on PTF.
We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2009 Annual Report on Form 10-K, including the financial statements and notes therein.
1 -- GENERAL INFORMATION
Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2009 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary to a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2010 are not necessarily indicative of the results which may be expected for the entire fiscal year 2010 because of seasonal and other factors.
Reclassifications: We have reclassified certain prior year financial statement amounts to conform to their current year presentation. These reclassifications had no effect on total assets, net income or earnings per share.
The reclassifications primarily relate to the reporting of discontinued operations reflecting the sale of Edison Sault. The footnotes contained herein reflect continuing operations for all periods presented. For further information, see Note 5 -- Discontinued Operations and Divestitures.
Amendments to Variable Interest Entity Consolidation Guidance: In June 2009, the Financial Accounting Standards Board issued new accounting guidance related to variable interest entity consolidation. The purpose of this guidance is to improve financial reporting by enterprises with variable interest entities. The new guidance is effective for all new and existing variable interest entities for fiscal years beginning after November 15, 2009. We adopted these provisions on January 1, 2010. This adoption did not have any impact on our financial condition, results of operations or cash flows. See Note 12 -- Variable Interest Entities for required disclosures.
3 -- Accounting and Reporting for Power the Future Generating Units
Background: As part of our PTF strategy, our non-utility subsidiary, We Power, has built three new generating units, Port Washington Generating Station Unit 1 (PWGS 1), Port Washington Generating Station Unit 2 (PWGS 2) and Oak Creek expansion Unit 1 (OC 1), and is in the process of building another new generating unit, Oak Creek expansion Unit 2 (OC 2), which are, and will be, leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the Public Service Commission of Wisconsin (PSCW). The leases are designed to recover the capital costs of the plant, including a return. PWGS 1, PWGS 2 and OC 1 were placed in service in July 2005, May 2008 and February 2010, 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 will benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system, which were placed in service in November 2007 and January 2009, respectively.
During Construction: Under the terms of each lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our PTF units. Our pre-tax cost of capital is approximately 14%. The carrying costs that we collect in rates are recorded as deferred revenue and will be amortized to revenue over the term of each lease once the respective unit is placed in service. During the construction of our PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest which was approximately 5% for the nine months ended September 30, 2010 and for the twelve months ended December 31, 2009. Capitalized interest is included in the total cost of the PTF units.
Plant in Service: Once the PTF units are placed in service, we expect to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return on the investment. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs are recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first five years of the leases. The leases established a set return on equity component of 12.7% after tax. The interest component of the return is determined up to 180 days prior to the date that the units are placed in service.
We recognize revenues (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 units on a straight-line basis over their expected service life.
4 -- COMMON EQUITY
Share-Based Compensation Expense: For a description of share-based compensation, including stock options, restricted stock and performance units, see Note J -- Common Equity in our 2009 Annual Report on Form 10-K. 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 outstanding stock options during the period. Shares purchased on the open market by our independent agents are currently used to satisfy share-based awards.
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:
Stock Option Activity: During the first nine months of 2010, the Compensation Committee granted 274,750 stock options that had an estimated fair value of $6.72 per share. During the first nine months of 2009, the Compensation Committee granted 1,216,625 stock options that had an estimated fair value of $8.01 per share. The following assumptions were used to value the options using a binomial option pricing model:
The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on our historical experience.
The following is a summary of our stock option activity for the three and nine months ended September 30, 2010:
The intrinsic value of options exercised was $26.8 million and $51.9 million for the three and nine months ended September 30, 2010, and $4.3 million and $8.2 million for the same periods in 2009, respectively. Cash received from options exercised was $76.0 million and $12.5 million for the nine months ended September 30, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $20.2 million and $3.3 million, respectively.
All outstanding stock options to purchase shares of common stock were included in the computation of diluted earnings per share during the third quarter of 2010.
The following table summarizes information about stock options outstanding as of September 30, 2010:
The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2010:
As of September 30, 2010, total compensation costs related to non-vested stock options not yet recognized was approximately $3.6 million, which is expected to be recognized over the next 12 months on a weighted-average basis.
Restricted Shares: During the first nine months of 2010, the Compensation Committee granted 46,740 restricted shares to certain key employees and directors. These awards have a three-year vesting period, with, typically, one-third of the award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients have voting rights and are entitled to dividends in the same manner as other shareholders.
The following restricted stock activity occurred during the three and nine months ended September 30, 2010:
Performance Units: In January 2010 and 2009, the Compensation Committee granted 277,915 and 333,220 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 period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2009 and 2008 vested and were settled during the first quarter of 2010 and 2009, and had a total intrinsic value of $9.8 million and $8.4 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $3.4 million and $3.1 million, respectively. As of September 30, 2010, total compensation costs related to performance units not yet recognized was approximately $32.0 million, which is expected to be recognized over the next 22 months on a weighted-average basis.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
Comprehensive Income: Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners.
Our total comprehensive income for the nine months ended September 30, 2010 and 2009 was $330.9 million and $264.0 million, respectively, which approximates net income for each of those periods.
5 -- DISCONTINUED OPERATIONS AND DIVESTITURES
Edison Sault Electric Company (Edison Sault): Effective May 4, 2010, we sold Edison Sault to Cloverland Electric Cooperative for approximately $63.0 million. Prior to the sale, we transferred certain assets to Wisconsin Energy, including Edison Sault's membership interest in American Transmission Company, LLC (ATC).
The assets and liabilities ($77.0 million and $15.1 million, respectively) associated with Edison Sault were reclassified as held for sale within other current assets and liabilities on our Consolidated Condensed Balance Sheet as of December 31, 2009. We also reclassified the income related to Edison Sault as discontinued operations in the accompanying Consolidated Condensed Income Statements. Discontinued Edison Sault operations had no significant impact on our Consolidated Condensed Statements of Cash Flows for the nine months ended September 30, 2010 and 2009, respectively.
The following table summarizes the net impacts of the discontinued operations on our earnings as of September 30, 2010 and 2009:
Edgewater Generating Unit 5: During the fourth quarter of 2009, we reached a contingent agreement to sell our 25% interest in Edgewater Generating Unit 5 to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp., for our net book value, including working capital. In March 2010, the agreement became effective and we are in the process of receiving regulatory approvals. The completion of the sale is subject to approval by applicable regulatory bodies, including the FERC, PSCW and Michigan Public Service Commission (MPSC). In June 2010, we received approval for the sale from FERC. If approved by the remaining regulatory bodies, we expect the sale to close by the end of 2010 and to realize proceeds of between $40 million and $45 million depending on the working capital balances and our level of capital investment in the unit prior to the sale.
6 -- LONG TERM DEBT
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.
7 -- 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 ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.
Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as Over-the-Counter (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 the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach Nuclear Power Plant (Point Beach). Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.
The following tables summarize the fair value of derivatives classified as Level 3 in the fair value hierarchy:
Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (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 8 -- 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 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.
8 -- 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 September 30, 2010, we recognized $37.4 million in regulatory assets and $17.3 million in regulatory liabilities related to derivatives in comparison to $19.1 million in regulatory assets and $10.3 million in regulatory liabilities as of December 31, 2009.
We record our current derivative assets on the balance sheet in Prepayments and other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $1.0 million is recorded in Other deferred charges and other assets and the long-term portion of our derivative liabilities of $1.8 million is recorded in Other deferred credits and other liabilities. Our Consolidated Condensed Balance Sheets as of September 30, 2010 and December 31, 2009 include:
Our Consolidated Condensed 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 three and nine months ended September 30, 2010 and 2009 follow:
As of September 30, 2010 and December 31, 2009, we have posted collateral of $23.3 million and $9.3 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in Prepayments and other current assets.
9 -- BENEFITS
The components of our net periodic pension and Other Post-Retirement Employee Benefits (OPEB) costs for the three and nine months ended September 30, 2010 and 2009 were as follows:
Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $16.0 million as of September 30, 2010 and $15.8 million as of December 31, 2009.
10 -- GUARANTEES
We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of September 30, 2010, we had the following guarantees:
We provide guarantees to support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.
Wisconsin Electric is subject to the potential retrospective premiums that could be assessed under its insurance program.
11 -- SEGMENT INFORMATION
Summarized financial information concerning our operating segments for the three and nine months ended September 30, 2010 and 2009 is shown in the following table:
12 -- 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 three 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 13 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 $376.3 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 for the nine months ended September 30, 2010 were $49.6 million. Our maximum exposure to loss is limited to the capacity payments under the contracts.
13 -- COMMITMENTS AND CONTINGENCIES
Environmental Matters: We periodically review our exposure for remediation costs as evidence becomes available indicating that our liability has changed. Given current information, 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.
Divestitures: Over the past several years, we have sold various businesses and assets. In connection with these sales, we have agreed to provide the respective buyers with customary indemnification provisions including, but not limited to, certain environmental, asbestos and product liability matters. In addition, pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We have established reserves as deemed appropriate for these indemnification provisions.
Income Taxes: During the first nine months of 2010, our federal unrecognized tax benefits decreased by $12.3 million as the result of payment of a tax obligation for a prior year.
14 -- SUPPLEMENTAL CASH FLOW INFORMATION
During the nine months ended September 30, 2010, we paid $101.2 million in interest, net of amounts capitalized, and $162.0 million in income taxes, net of refunds. During the nine months ended September 30, 2009, we paid $70.4 million in interest, net of amounts capitalized, and $1.9 million in income taxes, net of refunds.
As of September 30, 2010 and 2009, the amount of accounts payable related to capital expenditures was $18.2 million and $56.6 million, respectively.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2010
The following table compares our operating income by business segment and our net income during the third quarter of 2010 with the third quarter of 2009 including favorable (better (B)) or unfavorable (worse (W)) variances:
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
Our utility energy segment contributed $134.2 million of operating income during the third quarter of 2010, an increase of $59.9 million, or 80.6%, compared with the third quarter of 2009. The following table summarizes the operating income of this segment between the comparative quarters:
Electric Utility Revenues and Sales
The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2010 with the third quarter of 2009:
Our electric utility operating revenues increased by $144.5 million, or 21.2%, when compared to the third quarter of 2009. The most significant factors that caused a change in revenues were:
As measured by cooling degree days, the third quarter of 2010 was 115.0% warmer than the same period in 2009 and 41.8% warmer than normal. Collectively, retail sales to our residential and small commercial and industrial customers, who are more weather sensitive, increased by 15.5%. Sales to our large commercial and industrial customers increased by 11.0% during the third quarter of 2010 as compared to the same period in 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, increased significantly for the quarter. If these sales are excluded, sales to our large commercial and industrial customers increased by 4.1% for the third quarter of 2010 as compared to the third quarter of 2009. The $7.6 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the third quarter of 2010 as compared to the same period in 2009.
Fuel and Purchased Power
Our fuel and purchased power costs increased by $43.6 million, or 14.9%, when compared to the third quarter of 2009. This increase was primarily caused by the 15.7% increase in total MWh sales, partially offset by a 0.9% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 14.8% increase in generation from our lower cost coal units, which was sufficient to offset the impact of a 5.9% increase in coal and transportation costs and the increased cost of purchased power utilized as a result of the increased sales.
Gas Utility Revenues, Gross Margin and Therm Deliveries
A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2010 with the third quarter of 2009. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues increased by $4.9 million, or 4.0%, primarily because of higher natural gas prices.
The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2010 with the third quarter of 2009:
Our gas margins are seasonal and are primarily driven by the heating needs of our customers. The third quarter gas margins are historically the lowest of the year because of the lack of heating load. Our gas margins increased by $0.7 million, or 1.2%, when compared to the third quarter of 2009.
Our other operation and maintenance expense increased by $55.7 million, or approximately 16.8%, when compared to the third quarter of 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 $19.3 million higher in the third quarter of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased approximately $18.1 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.
Depreciation and Amortization Expense
Our depreciation and amortization expense decreased by $15.8 million, or approximately 20.0%, when compared to the third quarter of 2009, 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 are being returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it is being amortized to the income statement as we issue bill credits to customers. When the bill credits are issued to customers, we transfer cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. During the third quarter of 2010 and 2009, the Amortization of Gain was $55.2 million and $57.9 million, respectively. We expect that all remaining bill credits will be issued by December 31, 2010.
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 2 were placed in service in July 2005 and May 2008, respectively. The common facilities associated with the Oak Creek expansion consist of the water intake system, which was placed in service in January 2009, and the coal handling system and other smaller assets, which were placed in service prior to January 2009. OC 1 was placed in service in February 2010. We expect OC 2 to be placed in service during the fourth quarter of 2010; the guaranteed in-service date for OC 2 is November 28, 2010.
The table below reflects a full quarter's earnings for 2010 and 2009 for PWGS 1 and 2 and the common facilities for the Oak Creek expansion. It also reflects a full quarter's earnings for 2010 for OC 1. This segment reflects the lease revenues on these units, as well as the depreciation expense. The operating and maintenance costs associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.
CONSOLIDATED INTEREST EXPENSE, NET
Our gross interest costs increased by $7.6 million, or 13.1%, during the third quarter of 2010, primarily because of higher long-term debt balances compared to the same period in 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 $6.5 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 $14.1 million, or 36.7%, as compared to the third quarter of 2009.
CONSOLIDATED INCOME TAXES
For the third quarter of 2010, our effective tax rate applicable to continuing operations was 35.9% compared to 36.1% for the third quarter of 2009. For additional information, see Note H -- Income Taxes in our 2009 Annual Report on Form 10-K.
RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2010
The following table compares our operating income by business segment and our net income during the first nine months of 2010 with the first nine months of 2009 including favorable (better (B)) or unfavorable (worse (W)) variances:
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
Our utility energy segment contributed $410.1 million of operating income during the first nine months of 2010, an increase of $31.6 million, or 8.3%, compared with the first nine months of 2009. The following table summarizes the operating income of this segment between the comparative periods:
The increase in Operating Income for the nine months ended September 30, 2010 as compared to the same period in 2009 was primarily caused by favorable weather during 2010, partially offset by unfavorable recoveries of revenues associated with fuel and purchased power and milder winter weather in 2010. During the first nine months of 2010, we experienced unfavorable fuel recoveries of approximately $64 million. During the same period in 2009, we experienced favorable fuel recoveries of approximately $2 million. Although we received a fuel order from the PSCW in March 2010 allowing us to increase our rates on an interim basis, we expect to be in an unfavorable fuel recovery position for 2010. For additional information on the fuel order, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters - 2010 Fuel Recovery Request.
Electric Utility Revenues and Sales
The following table compares electric utility operating revenues and MWh sales by customer class during the first nine months of 2010 with the first nine months of 2009:
Our electric utility operating revenues increased by $220.1 million, or 10.9%, when compared to the first nine months of 2009. The most significant factors that caused a change in revenues were:
As measured by cooling degree days, the first nine months of 2010 were 98.1% warmer than the same period in 2009 and 36.8% warmer than normal. Collectively, retail sales to our residential and small commercial and industrial customers, who are more weather sensitive, increased by 5.2%. Sales to our large commercial and industrial customers increased by 11.0% during the first nine months of 2010 as compared to the same period in 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, increased significantly for the first nine months of the year. If these sales are excluded, sales to our large commercial and industrial customers increased by 3.9% for the first nine months of 2010 as compared to the first nine months of 2009. The $25.4 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the first nine months of 2010 as compared to the same period in 2009.
Fuel and Purchased Power
Our fuel and purchased power costs increased by $62.0 million, or 7.6%, when compared to the first nine months of 2009. This increase was primarily caused by the 8.1% increase in MWh sales, partially offset by a 0.4% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 12.7% increase in generation from our lower cost coal units, which was sufficient to offset the impact of a 5.4% increase in coal and transportation costs and the increased cost of purchased power utilized as a result of the increased sales.
Gas Utility Revenues, Gross Margin and Therm Deliveries
A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first nine months of 2010 with the first nine months of 2009. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $167.3 million, or 16.9%, primarily because of lower natural gas prices and milder weather.
The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2010 with the first nine months of 2009:
Our gas margins decreased by $18.4 million, or approximately 5.7%, when compared to the first nine months of 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, the first nine months of 2010 were 13.1% warmer than the same period in 2009 and 9.0% warmer than normal.
Other Operation and Maintenance Expense
Our other operation and maintenance expense increased by approximately $131.9 million, or 12.8%, when compared to the first nine months of 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 $62.7 million higher in the first nine months of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased approximately $42.6 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.
Depreciation and Amortization Expense
Our depreciation and amortization expense decreased by $46.4 million, or approximately 19.8%, when compared to the first nine months of 2009, 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
During the first nine months of 2010 and 2009, the Amortization of Gain was $151.8 million and $177.2 million, respectively. For 2010, we expect to see a reduction in the Amortization of Gain of approximately $34.6 million as compared to 2009 because of the scheduled decrease in Point Beach bill credits. We expect that all remaining Point Beach bill credits will be issued by December 31, 2010.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
The table below reflects nine months of earnings for 2010 and 2009 for PWGS 1 and 2 and the common facilities for the Oak Creek expansion. It also reflects eight months of earnings in 2010 for OC 1. This segment reflects the lease revenues on these units, as well as the depreciation expense. The operating and maintenance costs associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.
CONSOLIDATED OTHER INCOME, NET
Other income, net increased by approximately $1.5 million, or 6.3%, when compared to the first nine months of 2009. This increase primarily relates to increased Allowance for Funds Used During Construction (AFUDC) related to large construction projects during the first nine months of 2010 as compared to the same period in 2009.
CONSOLIDATED INTEREST EXPENSE, NET
Our gross interest costs increased by $17.0 million, or 9.6%, during the first nine months of 2010, primarily because of higher long-term debt balances compared to the same period in 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 $18.9 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 $35.9 million, or 30.2%, as compared to the first nine months of 2009.
CONSOLIDATED INCOME TAXES
For the first nine months of 2010, our effective tax rate applicable to continuing operations was 35.6% compared to 36.4% for the first nine months of 2009. For additional information, see Note H -- Income Taxes in our 2009 Annual Report on Form 10-K. We expect our 2010 annual effective tax rate to be between 35% and 36%.
LIQUIDITY AND CAPITAL RESOURCES
The following summarizes our cash flows from continuing operations during the first nine months of 2010 and 2009:
Cash provided by operating activities was $653.7 million during the nine months ended September 30, 2010, which was $220.0 million higher than the same period in 2009. This improvement was primarily because of lower contributions to benefit plans and higher cash earnings (net income plus depreciation and amortization), which were partially offset by higher cash taxes. During 2009, we contributed $289.3 million to our benefit plans. No such contributions were required in the first nine months of 2010. In addition, our cash earnings increased by approximately $36.7 million because of higher net income, which includes an offset of $160.1 million in increased tax payments because of lower deferred income taxes as compared to 2009.
Cash used in investing activities was $410.0 million during the nine months ended September 30, 2010, which was $66.0 million lower than the same period in 2009. Our capital expenditures decreased by $7.5 million and we realized higher proceeds from the sale of assets because of the $63.0 million sale of Edison Sault.
Cash used in financing activities during the nine months ended September 30, 2010 was $252.7 million, compared to cash provided by financing activities during the same period in 2009 of $20.3 million. Our operating cash flows during the first nine months of 2010 allowed us to increase our dividends and reduce our net debt levels. During the first nine months of 2010, we paid approximately $140.3 million in cash dividends and decreased our debt levels by a net amount of approximately $66.4 million.
During the first nine months of 2010, we received proceeds of $76.0 million related to the exercise of stock options, compared with $12.5 million during the same period in 2009. Instead of issuing new shares for these stock options, we instructed our plan agent to purchase common stock in the open market at a cost of $128.5 million, compared with $21.0 million during the first nine months of 2009. This cost is included in Purchase of common stock on our Consolidated Condensed Statements of Cash Flows.
CAPITAL RESOURCES AND REQUIREMENTS
As of September 30, 2010, our current liabilities exceeded our current assets by approximately $420.8 million. This negative working capital balance is a result of financing the construction of OC 2 with significant amounts of short-term debt and an increase in long-term debt due currently. Upon commercial operation of OC 2, we anticipate issuing long-term debt to replace short-term debt that was incurred during the construction of OC 2. We expect this transaction will significantly improve our working capital position.
We anticipate meeting our capital requirements during the remaining three months of 2010 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, including the Oak Creek financing discussed under working capital above. Beyond 2010, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings and the issuance of debt securities.
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 September 30, 2010, we had approximately $1.6 billion of available, undrawn lines under our bank back-up credit facilities, and approximately $518.6 million of short-term debt outstanding on a consolidated basis that was supported by the available lines of credit.
We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities as of September 30, 2010:
The following table shows our capitalization structure as of September 30, 2010, as well as an adjusted capitalization structure that we believe is more consistent with the manner in which the rating agencies currently view Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 (Junior Notes):
Included in Long-Term Debt on our Consolidated Condensed Balance Sheet as of September 30, 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.
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 September 30, 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.
Access to capital markets at a reasonable cost is determined in large part by credit quality. Any change in ratings or ratings outlooks may impact our cost of capital and access to the capital markets. In July 2010, S&P affirmed the ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas, Wisconsin Energy Capital Corporation (WECC) and Elm Road Generating Station Supercritical, LLC (ERGSS) and the stable ratings outlooks assigned to each company.
In June 2010, Fitch affirmed the ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas, WECC and ERGSS. Fitch also revised the ratings outlooks assigned to Wisconsin Energy, Wisconsin Electric, WECC and ERGSS from negative to stable, and affirmed the stable ratings outlook of Wisconsin Gas. Prior to these actions, Fitch revised its ratings guidelines on corporate and utility hybrid and preferred securities. These ratings guideline revisions reduced the ratings of Wisconsin Energy's Unsecured Junior
Notes and Wisconsin Electric's Preferred Stock one notch from BBB+ to BBB and from A to A -, respectively.
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 if it decides that the circumstances warrant the change.
Our estimated 2010, 2011 and 2012 capital expenditures reflecting actual costs through September 30, 2010 are as follows:
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.
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 continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 10 -- Guarantees and Note 12 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.
Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments were approximately $21.5 billion as of September 30, 2010 and December 31, 2009. Periodic payments made in the ordinary course of business were approximately the same as new commitments entered into during the first nine months of 2010, including the long-term debt issued in February 2010 in connection with the commercial operation of OC 1.
FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES
The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2009 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, our PTF strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.
POWER THE FUTURE
Under our PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. We Power leases the PWGS and OC 1 units to Wisconsin Electric under long-term leases, and Wisconsin Electric is currently recovering the lease payments in its electric rates. When OC 2 goes into service, we expect Wisconsin Electric to also recover those lease payments in rates. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2009 Annual Report on Form 10-K for additional information on PTF.
Oak Creek Expansion: OC 1 was placed in service in February 2010. We expect OC 2 to be placed in service during the fourth quarter of 2010; the guaranteed in-service date for OC 2 is November 28, 2010.
2010 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:
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:
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 is requesting 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 currently embedded in rates. This increase is 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. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. 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. On October 14, 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $256,000 annually, effective November 1, 2010.
2010 Fuel Recovery Request: On February 19, 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 is being 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. The revenues that we collect are subject to refund with interest at a rate of 10.4%. We expect PSCW review and final approval by the end of 2010.
2009 Fuel Order: Wisconsin Electric operates under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation of electricity for its retail customers in Wisconsin. Under the current fuel rules, a Wisconsin utility may request an emergency rate increase if projected costs fall outside of a prescribed range of costs which is 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 is currently auditing 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 current 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.
The PSCW staff has issued for comment a memorandum detailing different alternatives for calculating excess revenues. We do not believe the amount to be refunded to customers, if any, should be material. We anticipate a decision in this matter by the end of 2010.
Wisconsin Fuel Rules: Embedded within Wisconsin Electric's base rates is an amount to recover fuel costs. Under the current fuel rules, no adjustments are made to rates under the fuel cost adjustment clause as long as fuel and purchased power costs are expected to be within a band of the costs embedded in current rates for the 12-month period ending December 31. If, however, annual fuel costs are expected to fall outside of the band, and actual costs fall outside of established fuel bands, then we may file for a change in fuel recoveries on a prospective basis.
In June 2006, the PSCW opened a docket (01-AC-224) to consider revisions to the existing fuel rules (Chapter PSC 116). In April 2010, the Wisconsin legislature passed the Fuel Rule Bill, and the Governor signed it in May 2010. Under this bill, the PSCW will be required 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. As part of the new rules, the PSCW needs to establish, among other things, the size of the symmetrical band, define recoverable fuel and purchased power costs and determine how excess revenues should be calculated, if at all. In August 2010, the PSCW proposed new fuel rules pursuant to this legislation, which are subject to review and comment by the Wisconsin legislature. We expect new fuel rules to be effective in 2011.
Wisconsin Electric - Wisconsin Gas Merger: On April 1, 2010, Wisconsin Electric and Wisconsin Gas filed a joint application with the PSCW to merge Wisconsin Gas into Wisconsin Electric. On September 1, 2010, Wisconsin Electric and Wisconsin Gas filed a letter with the PSCW to withdraw the joint application because of uncertainty with the Wisconsin Fuel Rules.
Renewable Energy Portfolio: In July 2008, we completed the purchase of rights to a new wind farm site in Central Wisconsin, Glacier Hills Wind Park, and filed a request for a Certificate of Public Convenience and Necessity (CPCN) with the PSCW in October 2008. The PSCW approved the CPCN in January 2010. We currently expect to install 90 wind turbines with a total generating capacity of approximately 162 MW. This project is expected to cost between $360 and $370 million, excluding AFUDC. Construction commenced in May 2010, and we anticipate 2012 will be the first full year of operation.
In September 2009, we announced plans to construct 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. We believe the biomass plant will be eligible for either the federal production tax credit or the federal 30% investment tax credit. We currently expect to invest approximately $255 million, excluding AFUDC, in the plant and for it to be completed during the fall of 2013, subject to regulatory and other approvals. In March 2010, we filed a request for a Certificate of Authority for the project with the PSCW. We expect the PSCW to approve the Certificate of Authority no later than the first quarter of 2011.
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding our utility rates and other regulatory matters.
ELECTRIC TRANSMISSION AND ENERGY MARKETS
MISO: As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the Locational Marginal Pricing (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 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, 2010 through May 31, 2011. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.
Proposed New Coal Ash Regulation: We currently have a successful 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. Recently, however, the United States Environmental Protection Agency (EPA) issued a draft rule for public comment proposing various scenarios for regulating coal combustion products including classifying coal ash as hazardous waste. If coal ash is classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program. Curtailing our program could result in the loss of a revenue stream that helps to offset the cost of pollution control equipment and the activities necessary to collect the coal ash.
In addition, if coal ash is classified as hazardous waste and we terminate our coal ash utilization program, we could be required to dispose of the coal ash at a significant cost to the Company.
EPA Regulation of Greenhouse Gas Emissions under the Clean Air Act: In December 2009, the EPA issued its endangerment finding related to greenhouse gas emissions, which set in motion a regulatory process that is leading to regulation of greenhouse gas emissions from stationary sources, including electric generating units, absent legislative or other intervention by the Administration or Congress. On March 29, 2010, the EPA finalized its determination of when the Clean Air Act's permitting requirements for emissions from facilities, including electric generating units, would apply to greenhouse gas emissions. The regulation of stationary sources will occur in multiple steps in the coming years, with the first step scheduled to occur on January 2, 2011. The initial step covers sources that are already subject to EPA regulations for pollutants other than greenhouse gas and includes our generating facilities. Several parties have filed for judicial review of some of the EPA's new greenhouse gas rules. Regulation of greenhouse gas emissions from power plants will impact our ability to do maintenance or modify our existing facilities, and permit new facilities.
Clean Air Interstate Rule: The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005 to facilitate the states in meeting the 8-hour ozone and Fine Particulate Matter standards by addressing the regional transport of Sulfur Dioxide (SO2) and Nitrogen Oxide (NOx). In 2008, the U.S. Court of Appeals for the D.C. Circuit invalidated several aspects of CAIR and remanded the rule to the EPA to promulgate a replacement rule.
In July 2010, the EPA proposed a Transport Rule to replace CAIR. The proposed Transport Rule, like CAIR, would establish individual state caps for the emissions of SO2 and NOX from electric generating units in the eastern half of the United States, including Michigan and Wisconsin. The CAIR is in effect as of 2009 for NOx and 2010 for SO2, but will be replaced with the new requirements of the Transport Rule, if adopted. The Transport Rule may require new reductions in 2012 for NOx and SO2 and additional reductions in 2014 for SO2 for some states, including Wisconsin and Michigan. According to the EPA, the Transport Rule and other actions by States is expected to result in a 71% reduction of SO2 and 52% reduction of NOx emissions from power plants in the eastern United States by 2014 from 2005 emission levels.
We submitted comments on the proposed rule on October 1, 2010. The EPA intends to finalize the rule in mid-2011.
We previously determined that compliance with the NOx and SO2 emission reductions requirements under the Consent Decree entered into between the EPA and Wisconsin Electric in April 2003 would substantially mitigate costs to comply with CAIR and would achieve the levels necessary under at least the first phase of CAIR. The proposed limits under the Transport Rule appear to be more stringent and could result in the need for additional expenditures by 2014.
See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.
Cash Balance Pension Plan:On June 30, 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. Counsel representing the plaintiff is attempting to seek class certification for other similarly situated plaintiffs. The complaint alleges 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 are 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. On September 6, 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy Corporation as a defendant. The plaintiff has not specified the amount of relief he is seeking. An adverse outcome of this lawsuit could have a material adverse effect on Plan funding and expense and our results of operations. Although we are currently unable to predict the final outcome or impact of this litigation, we are aware that a court in a similar lawsuit filed in Wisconsin found that the interest crediting rates applied by pension plans involved in that case were not in compliance with ERISA.
Used Nuclear Fuel and Storage Disposal:The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of nuclear plants. Wisconsin Electric owned Point Beach through September 2007 and placed approximately $215.2 million into this fund. Effective January 31, 1998, the United States Department of Energy (DOE) failed to meet its contractual obligation to begin removing used fuel from Point Beach. Wisconsin Electric filed a complaint in November 2000 against the DOE in the Court of Federal Claims for failure to begin performance. 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 anticipate that any recoveries will be included in future rate cases.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For information concerning market risk exposures at Wisconsin Energy Corporation, see Item 7. 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 Part II of our 2009 Annual Report on Form 10-K.
Disclosure Controls and Procedures: Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting: There has not been any change in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II -- OTHER INFORMATION
The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2009 Annual Report on Form 10-K.
In addition to those legal proceedings discussed in our reports to the SEC, 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 legal proceedings cannot be predicted with certainty, we believe, after consultation with legal
counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.
UTILITY RATES AND REGULATORY MATTERS
See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where Wisconsin Electric and Wisconsin Gas do business.
See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Part I of this report for information on additional legal proceedings.
ITEM 1A. RISK FACTORS
See Item 1A. Risk Factors in our 2009 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended September 30, 2010:
ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. EXHIBITS
Pursuant to the requirements 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.