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Wisconsin Energy DEF 14A 2006 Documents found in this filing:Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
SCHEDULE 14A
Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 (Amendment No. )
Filed by the Registrant x
Filed by a Party other than the Registrant ¨
Check the appropriate box:
Wisconsin Energy Corporation (Name of Registrant as Specified In Its Charter)
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
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NOTICE OF ANNUAL MEETING OF STOCKHOLDERS March 16, 2006 To the Stockholders of Wisconsin Energy Corporation: You are cordially invited to attend the 2006 Annual Meeting of Stockholders. An admission ticket will be required to enter the meeting. Your admission ticket, which also includes a map to the meeting, is attached to your proxy statement. Instructions on how to obtain an admission ticket if you received your proxy materials electronically are provided on page 2 of the proxy statement. Regardless of whether you plan to attend, please take a moment to vote your proxy. The Meeting will be held as follows:
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Table of ContentsPROXY STATEMENT This proxy statement is being furnished to stockholders beginning on or about March 16, 2006, in connection with the solicitation of proxies by the Wisconsin Energy Corporation (“WEC” or the “Company”) Board of Directors (the “Board”) to be used at the Annual Meeting of Stockholders on Thursday, May 4, 2006 (the “Meeting”) at 10:00 a.m., Central time, at the Pettit National Ice Center located at 500 South 84th Street, Milwaukee, Wisconsin 53214, and at all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders. GENERAL INFORMATION – FREQUENTLY ASKED QUESTIONS
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PROPOSAL 1: ELECTION OF DIRECTORS – TERMS EXPIRING IN 2007 WEC’s Bylaws require each director to be elected annually to hold office for a one-year term. Directors will be elected by a plurality of the votes cast by the shares entitled to vote, as long as a quorum is present. “Plurality” means that the individuals who receive the largest number of votes are elected as directors up to the maximum number of directors to be chosen. Therefore, shares not voted, whether by withheld authority or otherwise, have no effect in the election of directors. The Board’s nominees for election are:
Although John F. Ahearne’s age exceeds the Company’s age guideline for non-employee directors, the guideline permits the Board to request a director to remain on the Board. The Corporate Governance Committee determined that Director Ahearne’s expertise in the nuclear field is unique among Board members, and the Board is nominating him on that basis. Pursuant to authority granted to the Board under the Bylaws, Thomas J. Fischer was elected as a director by the Board effective July 21, 2005. George E. Wardeberg is not standing for re-election at the Meeting, and the Board has determined to reduce the number of directors constituting the whole Board from ten to nine. Proxies may not be voted for more than nine persons in the election of directors. Each nominee has consented to being nominated and to serve if elected. In the unlikely event that any nominee becomes unable to serve for any reason, the proxies will be voted for a substitute nominee selected by the WEC Board upon the recommendation of the Corporate Governance Committee of the Board. Biographical information regarding each nominee is shown on the next pages. The Board of Directors recommends that you vote “FOR” all of the director nominees.
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Table of ContentsINFORMATION ABOUT NOMINEES FOR ELECTION TO THE BOARD OF DIRECTORS Wisconsin Electric Power Company (WE) and Wisconsin Gas LLC (WG) do business as We Energies and are wholly-owned subsidiaries of Wisconsin Energy Corporation. Effective July 28, 2004, Wisconsin Gas Company converted to a Wisconsin limited liability company and changed its name to Wisconsin Gas LLC. References to service as a director of Wisconsin Gas LLC below include the time each director sat as a director of Wisconsin Gas Company. Ages are as of March 16, 2006.
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Table of ContentsPROPOSAL 2: RATIFICATION OF DELOITTE & TOUCHE LLP AS INDEPENDENT AUDITORS FOR 2006 The Audit and Oversight Committee of the Board of Directors has sole authority to select, evaluate and, where appropriate, terminate and replace the independent auditors. The Audit and Oversight Committee has appointed Deloitte & Touche LLP as the Company’s independent auditors for the fiscal year ending December 31, 2006. The Committee believes that stockholder ratification of this matter is important considering the critical role the independent auditors play in maintaining the integrity of the Company’s financial statements. If stockholders do not ratify the selection of Deloitte & Touche LLP, the Audit and Oversight Committee will reconsider the selection. Deloitte & Touche LLP also served as the independent auditors for the Company for the fiscal years ended December 31, 2005, 2004, 2003 and 2002. Representatives of Deloitte & Touche LLP are expected to be present at the Meeting. They will have an opportunity to make a statement if they so desire and are expected to respond to appropriate questions that may be directed to them. The appointment of Deloitte & Touche LLP as independent auditors for 2006 will be ratified if the number of votes cast in favor of the proposal exceeds the number of votes cast against the proposal. Accordingly, presuming a quorum is present, abstentions and broker non-votes will have no effect on the outcome of this proposal. The Board of Directors recommends that you vote “FOR” the ratification of Deloitte & Touche LLP as independent auditors for 2006.
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Table of ContentsINDEPENDENT AUDITORS’ FEES AND SERVICES Pre-Approval Policy. The Audit and Oversight Committee has a formal policy delineating its responsibilities for reviewing and approving, in advance, all audit, audit-related, tax and other services of the independent auditors. The Committee is committed to ensuring the independence of the auditors, both in appearance as well as in fact. Under the pre-approval policy, before engagement of the independent auditors for the next year’s audit, the independent auditors will submit a detailed description of services anticipated to be rendered for the Committee to approve. Annual pre-approval will be deemed effective for a period of twelve months from the date of pre-approval, unless the Committee specifically provides for a different period. A fee level will be established for all permissible non-audit services. Any proposed non-audit services exceeding this level will require additional approval by the Committee. The Audit and Oversight Committee delegated pre-approval authority to the Committee’s chair. The Committee Chair shall report any pre-approval decisions at the next scheduled Committee meeting. Under the pre-approval policy, the Committee shall not delegate to management its responsibilities to pre-approve services performed by the independent auditors. Under the pre-approval policy, prohibited non-audit services are services prohibited by the Securities and Exchange Commission to be performed by the Company’s independent auditors. These services include bookkeeping or other services related to the accounting records of the Company, financial information systems design and implementation, appraisal or valuation services, fairness opinions or contribution-in-kind reports, actuarial services, internal audit outsourcing services, management functions, human resources, broker-dealer, investment advisor or investment banking services, legal services and expert services unrelated to the audit. In addition, the Committee has determined that tax services performed by the independent auditors should not involve tax strategy consulting. Fee Table. The following table shows the fees for professional audit services provided by Deloitte & Touche LLP for the audit of the annual financial statements of the Company and its subsidiaries for fiscal years 2005 and 2004 and fees for other services rendered during those periods. No fees were paid to Deloitte & Touche LLP pursuant to the “de minimus” exception to the pre-approval policy permitted under the Securities and Exchange Act of 1934, as amended.
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Table of ContentsCORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS
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Table of ContentsCOMMITTEES OF THE BOARD OF DIRECTORS
The Board also has an Executive Committee which may exercise all powers vested in the Board except action regarding dividends or other distributions to stockholders, filling Board vacancies and other powers which by law may not be delegated to a committee or actions reserved for a committee comprised of independent directors. The members of the Executive Committee are Gale E. Klappa (Chair), John F. Bergstrom, Barbara L. Bowles, Robert A. Cornog and Frederick P. Stratton, Jr. The Executive Committee did not meet in 2005. The Board dissolved the Nuclear Oversight Committee in 2005, but named Director Ahearne as lead nuclear director. In addition to the number of committee meetings listed in the preceding table, the Board met six times in 2005 and executed two signed, written unanimous consents. The average meeting attendance during the year was 95%. No director attended fewer than 87% of the total number of meetings of the Board and Board committees on which he or she served.
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Table of ContentsAUDIT AND OVERSIGHT COMMITTEE REPORT The Audit and Oversight Committee, which is comprised solely of independent directors, oversees the integrity of the financial reporting process on behalf of the Board of Directors of Wisconsin Energy Corporation. In addition, the Committee oversees compliance with legal and regulatory requirements. The Committee operates under a written charter approved by the Board of Directors, which can be found in the “Governance” section of the Company’s website at www.wisconsinenergy.com, and is attached hereto as Appendix A. The Committee is also responsible for the appointment, compensation, retention and oversight of the Company’s independent auditors, as well as the oversight of the Company’s internal audit function. The Committee selected Deloitte & Touche LLP to remain as the Company’s independent auditors for 2006, subject to stockholder ratification. Management is responsible for the Company’s financial reporting process, the preparation of consolidated financial statements in accordance with generally accepted accounting principles and the system of internal controls and procedures designed to provide reasonable assurance regarding compliance with accounting standards and applicable laws and regulations. The Company’s independent auditors are responsible for performing an independent audit of the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) and issuing a report thereon. The Committee held seven meetings during 2005. Meetings are designed to facilitate and encourage open communication among the members of the Committee, management, the internal auditors and the Company’s independent auditors, Deloitte & Touche LLP. During these meetings, we reviewed and discussed with management, among other items, the Company’s quarterly and annual financial statements and the system of internal controls designed to provide reasonable assurance regarding compliance with accounting standards and applicable laws. We reviewed the financial statements and the system of internal controls with the Company’s independent auditors, both with and without management present, and we discussed with Deloitte & Touche LLP matters required by Statement on Auditing Standards No. 61, as amended, relating to communications with audit committees, including the quality of the Company’s accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements. In addition, we received the written disclosures and the letter relative to auditors’ independence from Deloitte & Touche LLP, as required by Independence Standards Board Standard No. 1. The Committee discussed this information with Deloitte & Touche LLP and also considered the compatibility of non-audit services provided by Deloitte & Touche LLP with maintaining its independence. Based on these reviews and discussions, the Audit and Oversight Committee recommended to the Board of Directors that the audited financial statements be included in Wisconsin Energy Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 and filed with the Securities and Exchange Commission. Respectfully submitted to Wisconsin Energy Corporation stockholders by the Audit and Oversight Committee of the Board of Directors. Frederick P. Stratton, Jr., Committee Chair John F. Bergstrom Barbara L. Bowles Robert A. Cornog Curt S. Culver Thomas J. Fischer Ulice Payne, Jr.
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Table of ContentsCOMPENSATION OF THE BOARD OF DIRECTORS During 2005, each non-employee director received an annual retainer fee of $36,000. Non-employee chairs of Board committees received a quarterly retainer of $1,250. Non-employee directors received a fee of $1,500 for each Board or committee meeting attended. In addition, each non-employee director received a per diem fee of $1,250 for travel on Company business for each day on which a Board or committee meeting was not also held, and the Company reimbursed non-employee directors for all out-of-pocket travel expenses. Non-employee directors were paid $300 for each signed, written unanimous consent in lieu of a meeting. The lead nuclear director received a quarterly retainer of $1,250, an attendance fee of $1,500 for each business meeting/site visit and a per diem fee of $1,250 for travel on Company business for each day on which a business meeting/site visit was not also held. Each non-employee director also received on January 3, 2005, the 2005 annual stock compensation award in the form of restricted stock equal to a value of $65,000, with vesting to occur three years from the grant date. Insurance is also provided by the Company for director liability coverage, fiduciary and employee benefit liability coverage and travel accident coverage for director travel on Company business. Employee directors do not receive any directors’ fees. For 2006, the fees paid to non-employee directors will be the same as in 2005. In addition, each non-employee director received on January 3, 2006, the 2006 annual stock compensation award in the form of restricted stock equal to a value of $65,000, with vesting to occur three years from the grant date. Non-employee directors may defer all or a portion of director fees pursuant to the Directors’ Deferred Compensation Plan. Deferred amounts can be credited to any of ten measurement funds, including a WEC phantom stock account. The value of these accounts will appreciate or depreciate based on market performance, as well as through the accumulation of reinvested dividends. Deferral amounts are credited to accounts in the name of each participating director on the books of WEC, are unsecured and are payable only in cash following termination of the director’s service to WEC and its subsidiaries. The deferred amounts will be paid out of the general corporate assets or the assets of the trust described under “Retirement Plans” in this proxy statement. Although WEC directors also serve on the Wisconsin Electric Power Company and Wisconsin Gas LLC boards and their committees, a single annual retainer is paid and only a single fee is paid for meetings held on the same day. Fees are allocated among WEC, Wisconsin Electric Power Company and Wisconsin Gas LLC based on services rendered. In addition, the Board has adopted stock ownership guidelines for directors to further align the Board’s interests with stockholders. Under these guidelines, directors are generally expected, over time (generally within five years of commencement of Board service), to acquire and hold WEC common stock with a fair market value equal to five times the director’s annual retainer. The Company has established a Directors’ Charitable Awards Program to help further its philosophy of charitable giving. Under the program, the Company intends to contribute up to $100,000 per year for 10 years to one or more charitable organizations chosen by each director, upon the director’s death. Directors are provided with one charitable award benefit for serving on the boards of WEC and its subsidiaries. There is a vesting period of three years of service on the Board required for participation in this program. Charitable donations under the program will be paid out of general corporate assets. Directors derive no financial benefit from the program, and all income tax deductions accrue solely to the Company. The tax deductibility of these charitable donations mitigates the net cost to the Company.
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Table of ContentsON EXECUTIVE COMPENSATION Compensation Philosophy and Objectives. The Compensation Committee is responsible for making decisions regarding compensation for the executive officers of Wisconsin Energy Corporation and its principal subsidiaries. The Board of Directors has determined that all Committee members are independent. We seek to provide a competitive, performance-based executive compensation program that enables WEC to attract and retain key individuals and to motivate them to achieve WEC’s short- and long-term goals. We believe that a substantial portion of executive compensation should be at risk. As a result, WEC’s compensation plans have been structured so that the level of total compensation (consisting of compensation paid in the current year and long-term compensation under the Company’s 1993 Omnibus Stock Incentive Plan and Performance Unit Plan) is strongly dependent upon achievement of goals that are aligned with the interests of WEC’s stockholders and customers. During 2005, 73% to 80% of such total compensation paid to the named executive officers was tied to WEC performance as measured by goals established by the Committee each year. The primary elements of WEC’s executive compensation program are base salary, annual incentive compensation and long-term incentive compensation. Generally, for WEC executives, all elements of compensation are targeted at the 50th percentile of general industry practices — that is, we target compensation at the median levels paid for similar positions at companies with comparable revenue. In order to determine appropriate compensation levels, including the allocation between long-term and current year compensation and between cash and non-cash compensation, we rely upon a variety of sources for guidance, including compensation data compiled by Towers Perrin, an independent compensation consultant. We also consider the executive’s responsibilities and experience. We believe that the labor market for WEC executives is that of general industry in the United States. As a result, we rely upon an analysis of compensation data for companies in general industry with comparable revenues. Recognizing that a significant portion of WEC’s business is in the energy services industry, we also consider compensation data that analyzes the energy services industry. Specific values of 2005 compensation for the Chief Executive Officer and the four other most highly compensated executive officers are shown in the Summary Compensation Table. Our basis for determining each element of compensation is described below. With respect to executive compensation paid to the named executive officers other than Mr. Klappa, the Committee considered the recommendations of Mr. Klappa. Base Salary. For 2005, we targeted base salaries for WEC officers to be within 10% of the reported median of general industry. For Wisconsin Electric Power Company and Wisconsin Gas LLC officers, we targeted base salaries to be within 10% of the reported median of the energy services industry. We then made adjustments to these targeted amounts taking into consideration factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of Company operations. Base salaries for 2005 for each of the named executive officers are shown in the Summary Compensation Table under the heading of “Salary.” For 2006, the base salaries for Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, are $1,005,000, $582,000, $538,200, $424,872, and $360,528, respectively. Annual Incentive Compensation. The annual incentive plan provides for annual cash awards to executives based upon achievement of pre-established stockholder, customer and employee focused objectives. All payments under the plan are at risk. Payments are made only if performance goals are achieved, and awards may be less or greater than targeted amounts based on actual performance. Based upon a review of competitive practices for comparable positions at companies with comparable revenues and the executive’s responsibilities and experience, awards for 2005 were targeted at 35% to 100% of base salary; however, actual awards may range from 0% to 210% of base salary based upon performance. The plan also provides the Committee with the discretion to recognize individual performance. At the Committee’s direction, the annual incentive plan for 2005 was designed with a principal focus on financial results. In general, the annual incentive was dependent upon financial achievement determined by performance against targets for earnings from ongoing operations and cash flow. For 2005, the target for earnings from ongoing operations excluded the effects of asset sales not in the normal course of business, impairment charges and certain one-time tax benefits associated with state loss carry forwards. The Company’s financial performance exceeded the targets for 2005. Performance incentive awards could be increased or decreased by up to 10% based upon the Company’s performance in the operational areas of customer satisfaction (5%), supplier and workforce diversity (2.5%) and safety (2.5%). The Company’s performance in these operational areas, in the aggregate, increased awards by 0.625%. Based upon these results, awards paid to executives for 2005 exceeded the target levels. Awards to the named executive officers are shown in the Summary Compensation Table under the heading of “Bonus.” The annual incentive plan for 2006 will again depend upon financial achievement determined by Company performance against earnings from ongoing operations and cash flow targets. As was the case in 2005, the Company’s performance in the operational areas
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Table of Contentsof customer satisfaction, supplier and workforce diversity and safety will either increase or decrease final awards by up to 10%. In addition, the Committee retains discretion to consider individual performance when awarding incentive compensation. Long-Term Incentive Compensation. The Committee administers the Company’s 1993 Omnibus Stock Incentive Plan, as amended, which is a stockholder approved, long-term incentive plan designed to link the interests of executives and other key employees to long-term stockholder value. It allows for various types of awards tied to the performance of the Company’s common stock, including stock options, stock appreciation rights, restricted stock and performance shares. Historically, the Committee has primarily used stock options to deliver competitive long-term incentive opportunities. Beginning in 2004, in order to model best practices, the Committee modified the long-term incentive program to include a performance share component to complement stock option awards. With the use of performance shares, the amount of the benefit ultimately vested is dependent upon the Company’s total stockholder return over a three-year period, as compared to the total stockholder return of the Custom Peer Group identified in the “Performance Graph” section of this proxy statement. Total stockholder return is the calculation of total return (stock price appreciation plus reinvestment of dividends) based upon an initial investment of $100 and subsequent $100 investments at the end of each quarter during the three-year performance period. The Committee believes this measure better aligns executive financial interests with those of stockholders and long-term interests of customers. For 2005, the Committee adopted WEC’s Performance Unit Plan. The performance units granted under this plan are similar to performance shares except that upon vesting, the performance units will be settled in cash while the performance shares granted in 2004 will be settled in WEC common stock. Executives receive a cash dividend when WEC declares a dividend on its common stock in an amount equal to the number of performance units and performance shares granted to the executive at the target 100% rate, as more fully described in “Long-Term Incentive Plans – Awards in Last Fiscal Year” in this proxy statement, multiplied by the amount of the dividend paid on a share of common stock. The dividends paid to the named executive officers in 2005 are included in the Summary Compensation Table under the heading “Other Annual Compensation.” For 2006, the Committee awarded performance units under the Performance Unit Plan. In December 2004, the Committee approved the acceleration of vesting of all unvested options awarded to executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the impact of the Financial Accounting Standards Board’s recent adoption of its statement, “Share-Based Payment” (SFAS 123(R)), which requires the expensing of unvested options over the remaining vesting period of the options beginning January 1, 2006. In connection with the acceleration of vesting, the Committee approved new terms and conditions governing the future award of options to purchase shares of WEC common stock. The terms and conditions are substantially similar to those of options that had been awarded since 2000, except that each new option will be a non-qualified stock option and will not vest at all until three years from the date of grant at which time the new options will become 100% exercisable. In addition, the new options will become immediately exercisable upon (i) a termination of employment with WEC or its subsidiaries by reason of retirement, disability or death or (ii) a change in control of WEC. These new terms govern the options granted on January 18, 2005. The Committee believes that an important adjunct to the long-term incentive program is significant stock ownership by officers who participate in the program. Accordingly, we have implemented stock ownership guidelines for officers of the Company. The guidelines provide that each executive officer should, over time (generally within five years of appointment as an executive officer), acquire and hold Company common stock having a minimum fair market value ranging from 150% to 300% of base salary. Chief Executive Officer Compensation. The assessment of the Chief Executive Officer’s performance and determination of the CEO’s compensation are among our principal responsibilities. In reviewing the performance of WEC’s Chief Executive Officer, we requested that all non-employee directors evaluate the CEO’s performance. The Committee chair reviewed the evaluations, met with Mr. Klappa to discuss them, and the Committee factored the results into our compensation determinations. Mr. Klappa’s salary was $961,752 for 2005. Mr. Klappa’s base salary for 2005 as Chairman, President and Chief Executive Officer was targeted at the median for CEOs at companies with comparable revenues as reflected in the survey of general industry compensation practices. Mr. Klappa’s annual incentive compensation award was targeted at 100% of base pay. The award for 2005 was $1,929,511, or 200.625% of base salary, and was based upon achievement of the financial and operational objectives described above under Annual Incentive Compensation.
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Table of ContentsIn view of the discretionary component of the annual incentive plan, the Committee also noted other significant accomplishments of Mr. Klappa in 2005. However, given the overall achievements by the Company with regard to its financial and operational goals, no adjustment to Mr. Klappa’s annual incentive award was made. Significant accomplishments for Mr. Klappa included, among other things:
To specifically link a portion of his compensation to the enhancement of long-term stockholder value, Mr. Klappa was awarded long-term incentive compensation in 2005 in the form of stock options, as set forth in the “Long-Term Compensation Awards” column of the Summary Compensation Table, and performance units, as set forth in “Long-Term Incentive Plans – Awards in Last Fiscal Year.” Compliance with Tax Regulations Regarding Executive Compensation. Section 162(m) of the Internal Revenue Code limits the deductibility of certain executives’ compensation that exceeds $1 million per year, unless certain requirements are met. It is our policy to take reasonable steps to obtain the corporate tax deduction by qualifying for the exemptions from the limitations on such deductibility under Section 162(m) to the extent practicable. Nevertheless, maintaining tax deductibility is but one consideration among many in the design of the executive compensation program. With respect to incentive compensation, long-term incentive compensation payable under the 1993 Omnibus Stock Incentive Plan, as amended, has been designed to comply with the requirements of Section 162(m), while annual incentive compensation awards and performance unit awards under WEC’s Performance Unit Plan have not been qualified under Section 162(m). The Committee may, from time to time, conclude that compensation arrangements are in the best interest of the Company and its stockholders despite the fact that such arrangements might not, in whole or in part, qualify for tax deductibility. Respectfully submitted to Wisconsin Energy Corporation’s stockholders by the Compensation Committee of the Board of Directors. John F. Bergstrom, Committee Chair John F. Ahearne Ulice Payne, Jr.
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Table of ContentsPERFORMANCE GRAPH The performance graph below shows a comparison of the cumulative total return, assuming reinvestment of dividends, over the last five years had $100 been invested at the close of business on December 31, 2000, in each of:
WEC uses the Custom Peer Group Index for peer comparison purposes because the Company believes the Index provides an accurate representation of WEC’s peers. The Custom Peer Group Index is a market-capitalization-weighted index consisting of 30 companies, including WEC. These companies are similar to WEC in terms of business model and long-term strategies. As noted elsewhere in this proxy statement, a comparison of WEC’s total stockholder return to the total stockholder return of the Custom Peer Group is used to determine a portion of the long-term executive compensation awards. The companies in the Custom Peer Group Index are Allegheny Energy, Inc.; Alliant Energy Corporation; Ameren Corporation; American Electric Power Company, Inc.; Avista Corporation; Cinergy Corp.; Consolidated Edison, Inc.; DTE Energy Company; Energy East Corporation; Entergy Corporation; Exelon Corporation; FirstEnergy Corp.; FPL Group, Inc.; NiSource Inc.; Northeast Utilities; Nstar; OGE Energy Corp.; Pinnacle West Capital Corporation; Pepco Holdings, Inc.; Progress Energy Inc.; Public Service Enterprise Group Incorporated; Puget Energy, Inc.; SCANA Corporation; Sempra Energy; Sierra Pacific Resources; The Southern Company; Westar Energy, Inc.; Wisconsin Energy Corporation; WPS Resources Corporation; and Xcel Energy Inc. Five-Year Cumulative Return Chart
Value of Investment at Year-End
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Table of ContentsEXECUTIVE OFFICERS’ COMPENSATION This table summarizes, for the last three fiscal years, compensation awarded to, earned by or paid to WEC’s Chief Executive Officer and each of WEC’s other four most highly compensated executive officers (the “named executive officers”). Summary Compensation Table
During 2005, the Company awarded performance units to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé. These performance units are not reflected in the table or footnote discussion above. These performance unit awards are reflected in the table under the heading “Long-Term Incentive Plans – Awards in Last Fiscal Year.”
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Option Grants in Last Fiscal Year This table shows additional data regarding the options granted in 2005 to the named executive officers.
Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values The following table reflects options exercised in 2005 and the number and value of exercisable and unexercisable “in-the-money” options held by the named executive officers at fiscal year-end.
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Long-Term Incentive Plans – Awards in Last Fiscal Year The following table provides information on long-term incentive plan awards in 2005 to the named executive officers.
The table set forth above reflects the award of performance units to the named executive officers in 2005 under the Wisconsin Energy Corporation Performance Unit Plan. Upon vesting, the performance units will be settled in cash in an amount determined by multiplying the number of performance units which have become vested by the fair market value (the average of the high and low sales price on the relevant date) of the Company’s common stock on the date of vesting. The number of performance units ultimately vested is dependent upon WEC’s total stockholder return over a three-year period as compared to the total stockholder return of the Custom Peer Group identified in the “Performance Graph” section of this proxy statement. Several mergers have been announced by companies within the Custom Peer Group. Should these anticipated mergers occur during 2006, the Custom Peer Group will be slightly altered to reflect the merged entities for purposes of vesting of 2005 and 2004 performance awards. Total stockholder return is the calculation of total return (stock price appreciation plus reinvested dividends) based upon an initial investment of $100 and subsequent $100 investments at the end of each quarter during the three-year performance period. The regular vesting schedule for the performance units is as follows:
If the Company’s rank is between the benchmarks identified above, the vesting percentage will be determined by interpolating the appropriate vesting percentage. Except as discussed herein, unvested performance units are immediately forfeited upon a named executive officer’s cessation of employment with WEC prior to completion of the three-year performance period.
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Table of ContentsThe performance units will vest immediately at the target 100% rate upon (i) the termination of the named executive officer’s employment by reason of disability or death or (ii) a change in control of WEC while the named executive officer is employed by the Company. In addition, a prorated number of performance units (based upon the target 100% rate) will vest upon the termination of employment of the named executive officer by reason of retirement prior to the end of the three-year performance period. Named executive officers will receive a cash dividend when WEC declares a dividend on its common stock in an amount equal to the number of performance units granted to the named executive officer at the target 100% rate multiplied by the amount of the dividend paid on a share of common stock. The performance units have no voting rights attached to them. EMPLOYMENT AND SEVERANCE ARRANGEMENTS WEC has adopted severance policies that provide for severance benefits to designated executives and other key employees. The policies provide for severance benefits in the event of employment termination either in anticipation of or within a two-year period following a change in control by reason of discharge without cause or resignation with good reason, and allow for a deferral opportunity for participants who may become entitled to benefits. Under the current severance policies, participants have been designated into one of four benefit levels. Of the individuals named in the Summary Compensation Table, Mr. Salustro is a Tier 2 participant. Messrs. Klappa, Kuester and Leverett, and Ms. Rappé, do not participate in the severance policy, but each has a separate change in control and severance agreement as described below. Ms. Rappé entered into an employment agreement with the Company on July 28, 2005, which supersedes her participation in the severance policies. Tier 2 benefits provide generally for lump sum severance payments equal to three times the sum of the current base salary and the highest bonus in the last three years (or the then current target bonus, if higher), a pension lump sum for the equivalent of three years’ worth of additional service and three years’ continuation of health and life insurance coverage. An overall limit is placed on benefits to avoid federal excise taxes under the “parachute payment” provisions of the tax law. Mr. Salustro will not be entitled to these severance benefits upon his retirement. The Company has entered into written agreements with each of Messrs. Klappa, Kuester and Leverett, and Ms. Rappé, providing for certain employment and severance benefits as described below.
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Long-Term Incentive Compensation Plans Special Vesting Provisions. Under the terms of the Company’s long-term incentive compensation plans, including the 1993 Omnibus Stock Incentive Plan, as amended, and the Performance Unit Plan, awards are generally subject to special vesting provisions upon the occurrence of a defined change in control transaction, or the termination of employment by reason of retirement (as defined in the respective plan), disability (as defined in the respective plan) or death, unless the provision is superseded in an executive’s employment agreement. Under the plans, any outstanding stock options and restricted stock awards will generally become fully vested in all cases. Performance shares and performance units will generally become fully vested upon a change in control or the termination of employment by reason of death or disability, but generally vest on a prorated basis (based upon the target 100% rate) upon the termination of employment by reason of retirement. Benefits and Perquisites. The Company provides its executive officers with employee benefits and perquisites. Except as specifically noted elsewhere in this proxy statement, the employee benefits programs in which executive officers participate (which provide benefits such as medical benefits coverage, life insurance protection, retirement benefits and annual contributions to a qualified savings plan) are generally the same programs offered to substantially all of the Company’s salaried employees. The perquisites available to executive officers are generally made available to all officers at or above the level of vice president. These
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Table of Contentsperquisites include the availability of financial planning and payment of the cost of an annual physical exam. The Company also pays the periodic dues and fees for certain club memberships for the named executive officers and other designated officers. Death Benefit Only Plan. The Company maintains a Death Benefit Only Plan (“DBO”). Pursuant to the terms of the DBO, upon an officer’s death a benefit is paid to his or her designated beneficiary in an amount equal to the after-tax value of three times the officer’s base salary if the officer is employed by the Company at the time of death or the after-tax value of one times final base salary if death occurs post-retirement. All of the named executive officers participate in the DBO. RETIREMENT PLANS WEC maintains a defined benefit pension plan of the cash balance type (the “WEC Plan”) for most employees, including the named executive officers. The WEC Plan bases a participant’s defined benefit pension on the value of a hypothetical account balance. For individuals participating in the WEC Plan as of December 31, 1995, a starting account balance was created equal to the present value of the benefit accrued as of December 31, 1994, under the plan benefit formula prior to the change to a cash balance approach. That formula provided a retirement income based on years of credited service and final average compensation for the 36 highest consecutive months, with an adjustment to reflect the Social Security integrated benefit. In addition, individuals participating in the WEC Plan as of December 31, 1995, received a special one-time transition credit amount equal to a specified percentage varying with age multiplied by credited service and 1994 base pay. The present value of the accrued benefit as of December 31, 1994, plus the transition credit, was also credited with interest at a stated rate. For 1996 and thereafter, a participant receives annual credits to the account equal to 5% of base pay (including certain incentive payments, pre-tax deferrals and other items), plus an interest credit on all prior accruals equal to 4% plus 75% of the annual time-weighted trust investment return for the year in excess of 4%. Additionally, the WEC Plan provides that up to an additional 2% of base pay may be earned based upon achievement of earnings targets. The life annuity payable under the WEC Plan is determined by converting the hypothetical account balance credits into annuity form. Individuals who were participants in the WEC Plan on December 31, 1995, were “grandfathered” so that they will not receive any lower retirement benefit than would have been provided under the prior formula, had it continued. This amount will continue to increase until January 1, 2011, at which time it will be frozen. Upon retirement, participants will receive the greater of this amount or the cash balance. For the individuals listed in the Summary Compensation Table, estimated benefits under the “grandfathered” formula are higher than under the cash balance plan formula. Pursuant to the agreements discussed below, their benefits would currently be determined by the prior plan benefit formula. The following table sets forth estimated annual benefits payable in life annuity form on normal retirement for persons in various compensation and years of service classifications during 2005, based on the continuation of the “grandfathered” prior plan formula for WEC (including supplemental amounts providing additional benefits, which include elimination of any caps on compensation that can be recognized under the WEC Plan, described below in the “Other Retirement Benefits” section): Pension Plan Table – WEC Plan (Prior Plan Formula)
The compensation considered for purposes of the retirement plans and the various supplemental plans for Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, is $1,767,859, $985,712, $1,062,528, $790,632, and $445,713, respectively. These amounts represent the average compensation paid during the consecutive 36-month period for which such compensation is highest. Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, currently have or are considered to have 28, 33, 17, 34 and 23
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Table of Contentscredited years of service, respectively, under the various supplemental plans described below. Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, are not entitled to these supplemental benefits until they attain the age of 60. Other Retirement Benefits. Designated officers of WEC and Wisconsin Electric Power Company, including the named executive officers, participate in the Supplemental Executive Retirement Plan (“SERP”). The SERP provides monthly supplemental pension benefits to participants, which will be paid out of unsecured corporate assets, or the grantor trust described below, in an amount equal to the difference between the actual pension benefit payable under the WEC Plan and what such pension benefit would be if calculated without regard to any limitation imposed by the Internal Revenue Code on pension benefits or covered compensation. In addition, under the SERP, Mr. Salustro and Ms. Rappé also will receive a supplemental lifetime annuity, estimated to be between 8% and 10% of final average compensation depending on which pension payment option is selected. Except for a “change in control” of WEC, as defined in the SERP, no payments are made until after the participant’s retirement at or after age 60 or death. WEC has entered into an agreement with Mr. Salustro who cannot accumulate by normal retirement age the maximum number of years of credited service under the pension plan formula in effect immediately before the change to the cash balance formula. According to Mr. Salustro’s agreement, Mr. Salustro at retirement will receive supplemental retirement payments which will make his total retirement benefits at age 60 or older substantially the same as those payable to employees who are age 60 or older, who are in the same compensation bracket and who became plan participants at the age of 25, offset by the value of any qualified or non-qualified defined benefit pension plans of prior employers. Mr. Salustro has announced that he intends to retire no later than early 2007, at which time he will have reached the age of 60. WEC has entered into agreements with Messrs. Klappa, Kuester and Leverett to provide them with supplemental retirement benefits upon retirement at or after age 60. The supplemental retirement payments are intended to make the total retirement benefits payable to the executive comparable to that which would have been received under the WEC Plan as in effect on December 31, 1995, had the defined benefit formula then in effect continued until the executive’s retirement, calculated without regard to Internal Revenue Code limits, and as if the executive had started participation in the WEC Plan at age 27 for Mr. Klappa, at the age of 22 for Mr. Kuester, and on January 1, 1989 for Mr. Leverett. The retirement benefits payable to Messrs. Klappa, Kuester and Leverett will be offset by the value of any qualified or non-qualified defined benefit pension plans of prior employers. Pursuant to the terms of her employment agreement, Ms. Rappé’s SERP benefit is not subject to early retirement reduction factors if she retires at or after age 60. The WEC Amended Non-Qualified Trust, a grantor trust, has been established to fund certain non-qualified benefits, including the SERP, the Executive Deferred Compensation Plan, the Directors’ Deferred Compensation Plan and the agreements with the named executive officers. The plans and agreements provide for optional lump sum payments and, in the instance of a change in control and, absent a deferral election, mandatory lump sum payments without regard to whether the executive’s employment has terminated.
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Table of ContentsWEC COMMON STOCK OWNERSHIP Directors, Nominees and Executive Officers. The following table lists the beneficial ownership of WEC common stock of each director, nominee, named executive officer and all of the directors and executive officers as a group as of February 15, 2006. In general, “beneficial ownership” includes those shares as to which the indicated persons have voting power or investment power and stock options that are exercisable currently or within 60 days of February 15, 2006. Included are shares owned by each individual’s spouse, minor children or any other relative sharing the same residence, as well as shares held in a fiduciary capacity or held in WEC’s Stock Plus Investment Plan and 401(k) plan. None of these persons beneficially owns more than 1% of the outstanding common stock.
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Table of ContentsOwners of More than 5%. The following table shows stockholders who reported beneficial ownership of more than 5% of WEC common stock, based on the information they have reported. This information is based upon the Forms 13G filed in February 2006 and reflects stock holdings as of December 31, 2005.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company’s executive officers, directors and persons owning more than ten percent of WEC’s common stock to file reports of ownership and changes in ownership of equity and derivative securities of WEC with the Securities and Exchange Commission and the New York Stock Exchange. Specific due dates for those reports have been established, and the Company is required to disclose in this proxy statement any failure to file by those dates during the 2005 fiscal year. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2005 were complied with in a timely manner. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Pursuant to an agreement with WEC, Fidelity Management Trust Company (“Fidelity”), a wholly owned subsidiary of FMR Corp., holds and invests the assets of the Wisconsin Energy Corporation Employee Retirement Savings Plan (the “Plan”). Fidelity has managed the Plan’s assets since 1992. FMR Corp. became a beneficial holder of more than five percent of WEC common stock, exclusive of shares held in the Plan, in 2003. Pursuant to the terms of its agreement with Fidelity, the Company may be required to make payments to Fidelity and/or its affiliates directly; however, it is not currently required to do so. Fidelity and its affiliates are currently compensated through the customary management fees collected by Fidelity’s affiliated mutual funds in which some of the Plan’s assets are invested. AVAILABILITY OF FORM 10-K A copy (without exhibits) of WEC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, as filed with the Securities and Exchange Commission, is available without charge to any stockholder of record or beneficial owner of WEC common stock by writing to the Corporate Secretary, Anne K. Klisurich, at the Company’s principal business office, 231 West Michigan Street, P. O. Box 1331, Milwaukee, Wisconsin 53201. The WEC consolidated financial statements and certain other information found in the Form 10-K are provided in Appendix B to this proxy statement. The Form 10-K, along with this proxy statement and all of WEC’s other filings with the Securities and Exchange Commission, is also available in the “Investor Relations” section of the Company’s website at www.wisconsinenergy.com.
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Table of ContentsWISCONSIN ENERGY CORPORATION AUDIT AND OVERSIGHT COMMITTEE OF THE BOARD OF DIRECTORS CHARTER Approved: February 10, 2003 PURPOSE The principal purpose of the Audit and Oversight Committee (Committee) is to (A) assist the Board of Directors in carrying out its oversight responsibility of (i) the integrity of the Company’s financial statements, (ii) the Company’s compliance with legal and regulatory requirements, (iii) the independent auditor’s qualifications and independence, and (iv) the performance of the Company’s internal audit function and independent auditors, and (B) prepare the report that Securities and Exchange Commission rules require to be included in the Company’s proxy statement. With respect to item (i), preparation of the financial statements is the role of Company management, not the Committee. The Committee shall report all significant findings to the Board. COMPOSITION The Committee shall consist of three or more independent directors who are periodically appointed by the Board. Members shall serve at the pleasure of the Board and for such term or terms as the Board may determine. Each member shall, in the judgment of the Board, meet the independence standards of the New York Stock Exchange, the Sarbanes-Oxley Act of 2002 and the Securities and Exchange Commission. Each member shall be financially literate as the Board of Directors interprets such qualification in its judgment. The Board shall determine whether any director serving on the Committee is an “audit committee financial expert,” as such term is defined in the rules and regulations promulgated by the Securities and Exchange Commission. No director may serve as a member of the Committee if such director serves on the audit committees of more than three public companies unless the Board determines that such simultaneous service would not impair the ability of such director to effectively serve on the Committee and discloses this determination in Wisconsin Energy Corporation’s proxy statement. No member of the Committee may receive any compensation from the Company other than (i) directors’ fees which may be received in cash, stock options or other in-kind consideration, (ii) other deferred compensation for prior service that is not contingent on future service, and (iii) any other benefits that other directors receive for their service to the Company as a director. One of the directors shall be appointed Chair for a term to be determined by the Board and shall preside over the meetings of the Committee. In the event the Committee Chair is unable to serve as Chair for a specific meeting, he/she shall designate one of the Committee members to preside. DUTIES AND RESPONSIBILITIES The Committee shall have unrestricted access to the independent auditor, Company personnel and documentation pertinent to the scope of its duties and responsibilities. The duties and responsibilities of the Committee shall be to: Independent Auditor
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Annual and Interim Financials
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Internal Controls
Internal Auditor Meet at least semi-annually with the internal auditor to review internal audit’s independence, coordination with the independent auditor, staffing, audit scope, significant audit results, management’s responsiveness to recommendations, evaluation of internal control systems, and other relevant matters. Code of Business Conduct
Oversight of Legal/Litigation, Regulatory and Environmental Matters
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Risk Assessment and Risk Management Discuss the Company’s major risk exposures and the steps management has taken to monitor and control such exposures. In this regard, review the process used by the Board’s Finance Committee to discuss policies with respect to the Company’s risk assessment and risk management. Annual Performance Evaluation Produce and provide to the Board an annual performance evaluation of the Committee. The evaluation shall compare the performance of the Committee with the requirements of this Charter. Recommend to the Board any improvements to the Charter. Other
The Committee shall be notified promptly by management, the internal auditor or independent auditor of the discovery of fraudulent, questionable or illegal events which could have a material impact on the financial statements or reputation of the Company. MEETINGS The Committee shall meet once every fiscal quarter, or more frequently if circumstances warrant. As deemed necessary by the Committee, meetings shall be attended by Company personnel. Both the internal auditor and the independent auditor shall (i) meet alone with the Committee at each regularly scheduled meeting to discuss any matters that the Committee or any of these persons or firms believe should be discussed privately and (ii) have authority and are expected to contact the Committee on any matters requiring its attention. The Committee may obtain advice and assistance from outside legal, accounting or other advisors. The Committee may retain these advisors without seeking Board approval. The Committee may meet separately with management and request any officer, employee or Company’s outside counsel to attend a Committee meeting or to meet with any advisors or consultants to the Committee.
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Table of ContentsWISCONSIN ENERGY CORPORATION 2005 ANNUAL FINANCIAL STATEMENTS and REVIEW of OPERATIONS
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Table of ContentsSELECTED FINANCIAL AND OPERATING DATA WISCONSIN ENERGY CORPORATION CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
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Table of ContentsWISCONSIN ENERGY CORPORATION CONSOLIDATED SELECTED UTILITY OPERATING DATA
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Table of ContentsMANAGEMENT’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 our subsidiaries. Our utility energy segment, consisting of Wisconsin Electric Power Company (Wisconsin Electric) and Wisconsin Gas LLC (Wisconsin Gas), both doing business under the trade name of “We Energies”, and Edison Sault Electric Company (Edison Sault), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Our non-utility energy segment primarily consists of W.E. Power, LLC and its subsidiaries (collectively, 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. Cautionary Factors Regarding Forward - Looking Statements: Certain statements contained herein are “Forward-Looking Statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management’s expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, 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,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects” or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described under the heading “Cautionary Factors” below, other matters described under the heading Factors Affecting Results, Liquidity and Capital Resources below, and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) or otherwise described throughout this document. We disclaim any obligation to update these forward-looking statements. CORPORATE STRATEGY Business Opportunities We seek to increase shareholder value by leveraging on our core competencies. Our key corporate strategy, announced in September 2000, is Power the Future. This strategy is designed to address Wisconsin’s growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel-diverse, reasonably priced electric supply. It is also designed to improve the delivery of energy within our distribution systems to meet increasing customer demands and to support our commitment to improved environmental performance. Our Power the Future strategy, which is discussed further below, is expected to have a significant impact on our utility and non-utility energy segments. In July 2005, the first of four new electric generating units under our Power the Future strategy was placed into service. Since 2000, we have been selling our non-core assets to direct more attention to the utility business and to finance Power the Future while reducing our debt. Utility Energy Segment: We are realizing operating efficiencies in this segment through the integration of the operations of Wisconsin Electric and Wisconsin Gas. These operating efficiencies should increase customer satisfaction and reduce operating costs. In connection with our Power the Future strategy, we are improving our existing energy distribution systems and upgrading existing electric generating assets. In 2005, we increased our generating capacity by 545-megawatts with the completion of the first unit under the Power the Future strategy, and we plan to continue increasing our generating capacity through three additional electric generating units that We Power is constructing. Non-Utility Energy Segment: Our primary focus in this segment is to improve the supply of electric generation in Wisconsin. We Power was formed to design, construct, own and lease new generation assets under the Power the Future strategy. Power the Future Strategy: In February 2001, we filed a petition with the Public Service Commission of Wisconsin (PSCW) that would allow us to begin implementing our 10-year Power the Future strategy to improve the supply and reliability of electricity in Wisconsin. Power the Future is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. Under Power the Future, we plan to add new coal-fired and natural gas-fired generating capacity to the state’s power portfolio which would allow Wisconsin Electric to maintain approximately the same fuel mix as exists today. As part of our Power the Future strategy, we plan to (1) invest approximately $2.6 billion in 2,120 megawatts of new natural gas-fired and coal-
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Table of Contentsfired generating capacity at existing sites; (2) upgrade Wisconsin Electric’s existing electric generating facilities and (3) invest in upgrades of our existing energy distribution system. Subsequent to our February 2001 filing, the state legislature amended several laws, making changes which were critical to the implementation of Power the Future. In October 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed with Power the Future and for us to incur the associated pre-certification expenses. However, individual expenses are subject to review by the PSCW in order to be recovered. In November 2001, we created We Power to design, construct, own and lease the new generating capacity. Wisconsin Electric will lease each new generating facility from We Power as well as operate and maintain the new plants under 25- to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, we expect to recover the initial investments in We Power’s new facilities over the initial lease term. At the end of the leases, Wisconsin Electric will have the right to acquire the plants outright at market value or to renew the leases. Wisconsin Electric expects that payments under the plant leases will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law. Under our Power the Future strategy, we expect to meet a significant portion of our future generation needs through We Power’s construction of the Port Washington Generating Station (PWGS) and the Oak Creek expansion. As of December 31, 2005, we:
We expect to finance the majority of our Power the Future strategy with internally generated cash and debt financings. Additionally, in the future we expect to have some limited asset sales, but at levels significantly below the prior five year level. We expect to maintain our debt to total capital ratio, excluding environmental trust securities that we may issue, at no more than 61.5% during the period we are constructing our new gas- and coal-fired generation plants. We currently do not plan to issue any new equity as part of our Power the Future financing plan. Our primary risks under Power the Future are construction risks associated with the schedule and costs for both our Oak Creek expansion and the PWGS, continuing legal challenges to permits obtained and changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, obtaining the investment capital from outside sources necessary to implement the strategy, governmental actions and events in the global economy. For further information concerning Power the Future capital requirements, see Liquidity and Capital Resources below. You can find additional information regarding risks associated with the Power the Future strategy, as well as the regulatory process, and specific regulatory approvals in Factors Affecting Results, Liquidity and Capital Resources below.
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Table of ContentsDivestiture of Assets Our Power the Future strategy led to a decision to divest non-core businesses. These non-core businesses primarily included non-utility generation assets located outside of Wisconsin and a substantial amount of Wispark’s real estate portfolio, as well as our manufacturing business. In addition, in 2001 we contributed our transmission assets to the American Transmission Company LLC (ATC) and received cash proceeds of $119.8 million and an economic interest in ATC. Since 2000, we have received total proceeds of approximately $2.1 billion from the divestiture of assets as follows:
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Table of ContentsRESULTS OF OPERATIONS CONSOLIDATED EARNINGS The following table compares our operating income by business segment and our net income for 2005, 2004, and 2003.
The following table identifies significant items that are included in our Diluted Earnings per Share from Continuing Operations.
An analysis of contributions to operating income by segment and a more detailed analysis of results in 2005, 2004 and 2003 follow. UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME 2005 vs. 2004: Our utility energy segment contributed $542.4 million of operating income during 2005 compared with $528.6 million of operating income during 2004. During 2005, we experienced an increase in revenues due to favorable weather and pricing increases. Also, during 2004, we recorded severance costs under a voluntary severance program. The year to year increase in operating income was partially offset by higher fuel and purchased power costs and increased operation and maintenance expenses during 2005. We had two scheduled outages at our nuclear plant in 2005 in comparison to one scheduled outage in 2004. 2004 vs. 2003: Our utility energy segment contributed $528.6 million of operating income during 2004 compared with $544.1 million of operating income during 2003. During 2004, we experienced an increase in revenues due to base electric sales growth, and we benefited from lower bad debt expenses. However, these items were more than offset by higher pension and medical costs, severance costs recorded during the second half of 2004 and unfavorable weather.
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Table of ContentsThe following table summarizes our utility energy segment’s operating income during 2005, 2004 and 2003.
Electric Utility Gross Margin The following table compares our electric utility gross margin during 2005 with similar information for 2004 and 2003, including a summary of electric operating revenues and electric sales by customer class.
Electric Utility Revenues and Sales 2005 vs. 2004: During 2005, our total electric utility operating revenues increased by $250.7 million or 11.9% when compared with 2004 primarily due to favorable weather during the summer of 2005 and pricing increases. During 2005, we estimate that pricing increases contributed an additional $145.8 million of revenues than in 2004. The most significant impact to rates was a March 2005 interim order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power. In November 2005, Wisconsin Electric received the final rate order, which authorized an additional $7.7 million of annual revenues. Additional orders impacting rates in 2005 were the May 2004 and May 2005 orders received by Wisconsin Electric from the PSCW authorizing
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Table of Contentsannualized increases in electric rates of approximately $59.0 million and $59.7 million, respectively, primarily to cover construction costs associated with our Power the Future program. Total electric sales increased by 821.8 thousand megawatt-hours or 2.6% between 2005 and 2004. Residential sales volumes increased 6.3% due to the favorable summer weather in 2005. Total sales volumes to commercial/industrial customers increased 1.7% between comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 2.3% due to the favorable weather during the summer of 2005. We estimate that weather increased our electric revenues by approximately $68.8 million during 2005 as compared to the prior year. As measured by cooling degree days, 2005 was 114.7% warmer than in 2004. Sales volumes in the Resale-Utilities class decreased 52.6% primarily due to the reduced availability of base-load capacity for sale at competitive prices as a result of limited fuel supplies and outages. Sales volumes to municipal utilities, the other retail/municipal customer class, increased 12.8% between the periods due to higher off-peak demand from lower margin municipal wholesale power customers. 2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $85.4 million or 4.2% when compared with 2003 due to pricing increases and to growth in our base businesses, partially offset by the effects of unfavorable weather during the summer of 2004. During 2004, we received $54.5 million of higher operating revenues as a result of pricing increases which were not in effect during 2003. In May 2004, Wisconsin Electric received an order from the PSCW authorizing an annualized increase in electric rates of approximately $59.0 million to cover construction costs associated with our Power the Future program and to recover low income uncollectible expenses transferred to Wisconsin’s public benefits fund. In addition, two rate increases related to a rise in fuel and purchased power costs were implemented in March and October 2003, which increased revenues by approximately $16.3 million during 2004. Total electric sales increased by 465.0 thousand megawatt-hours or 1.5% between 2004 and 2003. Residential sales were down 0.6%, and small commercial/industrial sales were up just 1.1% due to the unfavorable weather during 2004. We estimate that the unfavorable weather reduced our electric revenues by approximately $28.6 million as compared to the prior year and by $20.7 million as compared to normal weather. As measured by cooling degree days, 2004 was 27.1% cooler than in 2003 and 38.1% cooler than normal. However, we estimate that customer growth and higher weather-normalized use per customer during 2004 mitigated much of the impact of unfavorable weather. Sales volumes to large commercial/industrial customers improved by 2.5%. Excluding our largest customers, two iron ore mines, sales volumes to our remaining large commercial/industrial customers improved by 1.5%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.1% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers. Electric Fuel and Purchased Power Expenses 2005 vs. 2004: Gross fuel and purchased power costs for our electric utilities increased by a total of $260.8 million during 2005 when compared with 2004. During 2005, we deferred $72.8 million of fuel and purchased power costs which resulted in a net increase of fuel and purchased power expense of $188.0 million or 32.1% during 2005 when compared to 2004. The increase in fuel and purchased power expense was driven by a 2.6% increase in megawatt-hour sales and an increase in our average cost of fuel and purchased power from $17.49 per megawatt-hour in 2004 to $22.44 per megawatt-hour in 2005, or 28.3% between the comparative periods. The increase in our average cost of fuel and purchased power is due primarily to (1) the reduced availability of nuclear generation due to scheduled refueling outages, (2) higher natural gas prices that increased the cost of power supplied by natural gas, (3) the impact of the implementation of the Midwest Independent Transmission System Operator, Inc.’s (MISO) bid based energy market (MISO Midwest Market) in April 2005 and (4) limitations on coal supplies due to transportation shortfalls. During 2005, we had two scheduled refueling outages at our nuclear plant and in 2004 we had one scheduled refueling outage. As a result, we had approximately 1,145,000 fewer megawatt hours of nuclear generation in 2005. Our average fuel cost for nuclear generation is approximately $5 per megawatt hour, while the average energy cost for purchased power was approximately $55 per megawatt hour. We estimate that the reduction in nuclear generation resulted in approximately $57 million of increased fuel and purchased power costs in 2005 as compared to 2004. During the 2005 outages we replaced both reactor vessel heads resulting in longer outages. This work, along with other planned maintenance, lasted longer than originally expected due to delays. During 2006,
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Table of Contentswe have one planned refueling outage at our nuclear plant. For more information regarding the scheduled refueling outages, see Factors Affecting Results, Liquidity and Capital Resources — Nuclear Operations. In 2005, we experienced significant increases in the cost of natural gas used in our own generating assets and in the price of purchased energy which is highly influenced by the price of natural gas. This increase was most significant in the last six months of 2005 due to market related factors including the hurricanes in the Gulf of Mexico. The average combined cost per megawatt hour of purchased energy and natural gas fired units in 2005 was 47.7% higher than in 2004, increasing total cost by approximately $77.2 million. In April 2005, we began participating in the MISO Midwest Market which fundamentally changed the way we dispatch our generating units and obtain purchased energy. As part of this new market, we are subject to new types of charges which, among other things, recognize the cost of transmission congestion, megawatt-hour losses and other costs associated with operating the generating units in an uneconomic fashion to support the MISO Midwest Market service territory. Because the State of Wisconsin has a constrained transmission system, we believe these costs are higher for us than in other parts of the MISO Midwest Market service territory. The incremental costs associated with the MISO Midwest Market charges identified above were approximately $28 million in 2005. For more information regarding MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources — Industry Restructuring and Competition — Electric Transmission and Energy Markets. Our 2005 operations were also adversely impacted by limitations on deliveries of coal supply due to the failure of our primary rail delivery supplier to deliver contracted quantities of coal to our units. The largest limitation was related to critical rail track maintenance in the Powder River basin. This, in turn, resulted in reduced coal deliveries of the coal which primarily serves our Oak Creek and Pleasant Prairie generating units from June through December 2005. In response to the reduced deliveries, we limited the generating capability of these units in off-peak periods and purchased more expensive replacement power and, where possible, took measures to purchase and transport higher cost coal in place of contracted supplies. We estimate that this increased our costs by approximately $52 million in 2005. For additional information on the decreased coal deliveries, see Factors Affecting Results, Liquidity and Capital Resources — Market Risks and Other Significant Risks — Commodity Price Risk below. Under the State of Wisconsin fuel rules, we are allowed to request recovery in fuel revenues if our projected fuel and purchased power costs exceed bands established by the PSCW. In March 2005, we received a rate order that allowed us to increase our annual revenues by $114.9 million (final order received in November 2005 for an annual increase of $122.6 million) due to increased fuel and purchased power costs. As provided under the Wisconsin rules, we are also allowed to request deferral for the costs associated with adverse events which materially impact fuel and purchased power costs which were not anticipated, or for which costs could not be reasonably estimated at the time of the fuel recovery request for consideration in future rate proceedings. During 2005, we deferred approximately $72.8 million of fuel and purchased power costs due to the extended outage at Point Beach Unit 2, the coal delivery problems and increased costs associated with the MISO Midwest Market. During 2005, we estimate that we under-recovered fuel and purchased power costs by $108.4 million before these deferred items. Adjusted for the allowed deferrals, our net under-recovered fuel and purchased power costs were approximately $35.6 million. 2004 vs. 2003: Total fuel and purchased power expenses for our electric utilities increased by $22.2 million or 3.9% during 2004 when compared with 2003. This increase is primarily due to our 1.5% increase in total megawatt-hour sales and to higher coal and purchased capacity costs. Increased availability of several of our coal-fired generating units during 2004 mitigated the rise in fuel and purchased power costs. Very cool summer weather significantly reduced our need to use higher cost peak generating units and purchased power during 2004, also mitigating the rise in fuel and purchased power costs between the comparative periods. 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 2005, 2004 and 2003.
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. The following table compares our gas utility gross margin and therm deliveries by customer class during 2005, 2004 and 2003.
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2005 vs. 2004: Gas utility gross margin increased by $8.7 million or 2.4% between comparative periods. This increase reflects $6.5 million of price increases which reflects the full year’s impact of a $25.9 million annual rate increase, which became effective in March 2004. Total therm deliveries were 4.9% higher during 2005 primarily due to increased transport gas deliveries of 124.2 million therms. Transport volumes increased between the comparative periods due to a higher amount of electric generation from natural gas within our service territory. A portion of these sales are eliminated in consolidation. Our margins on these transport gas volumes are significantly lower than our margins for retail gas sales. The price increases and increased transport volumes were offset, in part, by a decrease in residential therm deliveries. Residential therm deliveries decreased 2.3% as compared to 2004, due to slightly warmer weather and a decrease in use per customer that was driven in part by higher commodity prices. As measured by heating degree days, 2005 was less than 1% warmer than 2004. 2004 vs. 2003: Our total gas utility gross margin fell slightly from $362.8 million in 2003 to $361.5 million in 2004 due largely to a decrease in therm deliveries resulting from less favorable weather. Total therm deliveries were 4.7% lower during 2004 primarily due to weather. As measured by heating degree days, 2004 was 5.7% warmer than 2003 and 1.1% warmer than normal, which reduced heating load. We estimate that weather reduced gross margin by approximately $12.9 million between the comparative periods. Our gas margins were favorably impacted by a price increase that became effective in March 2004. This annual price increase of $25.9 million favorably impacted gas margins by $19.6 million in 2004. However, in 2004, we recognized $8.8 million less in gas cost incentive revenues under our gas cost recovery mechanisms when compared with 2003. Other Operation and Maintenance Expenses 2005 vs. 2004: Other operation and maintenance expenses increased by $47.4 million or 4.9% during 2005 compared with 2004. The most significant changes in our operation and maintenance expense related to increased lease costs and increased nuclear outage costs. Partially offsetting these increases were a charge in 2004 for severance costs related to the voluntary severance program and lower employee costs in 2005 due to fewer employees. The largest operations and maintenance increase for the utility energy segment related to $50.0 million of costs that we recognized under lease agreements between We Power and Wisconsin Electric in connection with our Power the Future plan. Initially, Wisconsin Electric defers the lease payments and then amortizes the payments to expense as we recover revenues from our customers under specific pricing agreements. As noted in the electric revenue discussion, in May 2004 and May 2005 the PSCW approved pricing increases to recover the Wisconsin retail portion of these lease costs. In addition to the increased lease costs, our nuclear operating and maintenance expense increased approximately $11.0 million due to two scheduled refueling outages in 2005 where we also replaced the reactor vessel heads. In 2004, we had one scheduled refueling outage and in 2006 we only have one scheduled refueling outage. This increase was partially offset by a $10.0 million settlement we received to resolve a vendor dispute. Additionally, in 2004 we recognized $28.2 million of severance related costs due to the voluntary severance program that was implemented in the second half of 2004. In 2005, we had approximately 210 fewer employees, which reduced operation and maintenance costs by $12.9 million.
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Table of ContentsBenefit costs increased $7.0 million between comparative periods due to increased pension and medical costs. In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. As a result of the Medicare Advantage program we anticipate that our 2006 post-retirement costs will be approximately $13.0 million less than our 2005 costs. However, we expect an increase in our 2006 pension costs to offset this reduction due to lower discount rates and lower than expected historical returns on plan assets. 2004 vs. 2003: Other operation and maintenance expenses increased by $72.0 million or 8.1% during 2004 compared with 2003. The largest increase related to $36.3 million of costs that we recognized under a lease agreement in connection our Power the Future plan. In May 2004, the PSCW approved a pricing increase to recover the Wisconsin retail portion of these lease costs. In addition to the lease costs, we also recognized $12.8 million of increased public benefits costs which were also included in the May 2004 price increase. In 2004, our benefit costs increased $15.0 million due to increased pension and medical costs. We also incurred $28.2 million of severance-related costs during 2004, primarily due to a voluntary severance program offered to certain management and represented employees in the second half of 2004. Partially offsetting these increases was an $11.9 million reduction in bad debt costs due to improved collections and the timing of a deferral order. Depreciation, Decommissioning and Amortization Expense 2005 vs. 2004: Depreciation, decommissioning and amortization expense increased by $8.6 million in 2005 as compared to 2004. This increase was primarily due to increased depreciable plant balances. In November 2005, the PSCW approved new depreciation rates which are effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense by approximately $17 million due to the lengthening of nuclear plant lives. 2004 vs. 2003: Depreciation, decommissioning and amortization expense decreased by $0.7 million in 2004 as compared to 2003. This slight decrease was due to a $7.7 million reduction in decommissioning expense in 2004 due to the tax impacts associated with rebalancing the nuclear decommissioning trusts. This decrease was partially offset by increased depreciation expense on increased depreciable plant balances. NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME Effective May 31, 2005, we sold our Calumet facility, which was previously included in the operations of the non-utility energy segment. As a result of this sale, we have determined that the Calumet operations meet the definition of discontinued operations under Statement of Financial Accounting Standards (SFAS) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of the Calumet operations. See Results of Operations — Discontinued Operations below for further information. The most significant subsidiary included in this segment is We Power, which constructs and owns power plants associated with our Power the Future plan and leases them to Wisconsin Electric. This segment reflects revenues billed under the PWGS Unit 1 lease and the depreciation expense related to PWGS Unit 1. The following table compares our non-utility energy segment’s operating income (loss) during 2005, 2004 and 2003.
2005 vs. 2004: Our non-utility energy segment had operating income of $19.5 million during 2005 compared with $4.6 million during 2004. The increase in operating income between the comparative periods is primarily due to Unit 1 at PWGS commencing service in July 2005. This unit had operating income of $18.9 million during its six months of operation in 2005.
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Table of Contents2004 vs. 2003: Our non-utility energy segment had operating income of $4.6 million during 2004 compared with an operating loss of $55.7 million in 2003. During 2003, we recorded $59.5 million of non-cash asset valuation charges related to our investment in an entity that owns a co-generation plant in Maine (Androscoggin) and to a natural gas power island which we sold in the fourth quarter of 2003. In 2003, we also realized gains on the sale of non-utility energy assets of $10.5 million. CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME In August 2005, we announced our intent to sell our Minergy Neenah facility, which was previously included in the operations of corporate and other affiliates. As a result of this announcement, we have determined that the Minergy Neenah operations meet the definition of discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of Minergy Neenah operations. See Results of Operations — Discontinued Operations below for further information. This segment primarily reflects the operations of Wispark and holding company costs that are not allocated to subsidiaries. 2005 vs. 2004: Corporate and other affiliates had operating income of $1.0 million in 2005 compared with an operating loss of $3.2 million in 2004. The improved results reflect increased earnings from Wispark. However, we are reducing our Wispark assets and we expect to see lower Wispark earnings in the future. 2004 vs. 2003: We had net corporate and other affiliates operating losses of $3.2 million during 2004 compared with net operating losses of $4.3 million in 2003. CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET The following table identifies the components of consolidated other income and deductions, net during 2005, 2004 and 2003.
2005 vs. 2004: Other income and deductions, net increased by $47.5 million in 2005 compared to 2004. In 2004, we recognized $22.9 million of debt redemption costs associated with the early redemption of approximately $500 million of long-term debt. Similar debt redemption costs were not incurred in 2005. We recognized higher carrying costs on deferred electric transmission costs of $6.6 million. The allowance for funds used during construction increased $6.4 million in 2005 due to a higher average balance of allowance for funds used during construction (AFUDC) - qualifying utility construction projects in 2005. 2004 vs. 2003: Other income and deductions, net decreased by $25.9 million in 2004 compared to 2003, primarily due to $22.9 million of debt redemption costs incurred during 2004. In connection with the sale of our manufacturing business, we used approximately $500 million of the sales proceeds for early redemption of long-term debt. CONSOLIDATED INTEREST EXPENSE 2005 vs. 2004: Total interest expense decreased by $20.0 million in 2005 compared with 2004. The decrease in interest expense primarily reflects lower average debt levels in 2005 as compared to 2004. During 2004, we reduced debt levels by $654.2 million primarily with proceeds from the sale of our manufacturing segment. However, due to the increased construction activity our year end debt balances have increased by $291.9 million. To the extent that we incur debt associated with construction in progress, we capitalize the interest costs in accordance with our accounting policies. 2004 vs. 2003: Total interest expense decreased by $20.4 million in 2004 compared with 2003. This decrease primarily reflects the reduction in debt levels due to the retirement of debt with the proceeds from the sale of our manufacturing business, which was effective July 31, 2004. From December 31, 2003 to December 31, 2004, we reduced our debt levels by $654.2 million or 15%.
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Table of ContentsCONSOLIDATED INCOME TAXES 2005 vs. 2004: Our effective tax rate applicable to continuing operations was 33.0% in 2005 compared to 37.7% in 2004. In 2005, we reversed $16.3 million of valuation allowances associated with state net operating loss carry forwards as we concluded that it was more likely than not that we would realize these benefits. Excluding this nonrecurring item, our effective tax rate was 36.6%. For further information see Note H — Income Taxes in the Notes to Consolidated Financial Statements. 2004 vs. 2003: In 2004, our effective income tax rate from continuing operations was 37.7% compared with a 35.5% rate during 2003. The increase in the effective tax rate is due primarily to the inability to deduct state income taxes on losses of certain non-utility subsidiaries. DISCONTINUED OPERATIONS Our discontinued operations include our manufacturing operations which were sold effective July 31, 2004, our Calumet facility which was sold in May 2005 and our Minergy Neenah facility. As of December 31, 2005, we are considering offers to sell our Minergy Neenah facility. The following table identifies the primary components of income from discontinued operations during 2005, 2004 and 2003.
Our 2005 earnings from discontinued operations reflect a gain on the sale of the Calumet facility, the favorable resolution of liabilities at Calumet and an adjustment to the carrying value of Minergy Neenah. Our 2004 earnings from discontinued operations reflect an after-tax gain of $152.3 million on the sale of our manufacturing business. Our 2004 earnings from discontinued operations also reflect valuation charges of $79.3 million after-tax related to Calumet and $17.6 million after-tax related to Minergy Neenah. Our 2003 earnings from discontinued operations reflect net operating earnings of $43.9 million related to our manufacturing segment. See Note D — Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements for further information regarding the transactions described above. LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS The following table summarizes our cash flows during 2005, 2004 and 2003:
Operating Activities Cash provided by continuing operating activities decreased to $576.9 million during 2005 compared with $599.0 million during 2004. This decline reflected increased working capital needs for our utility business and an increase in deferred costs, offset in part by lower cash taxes and increased cash earnings. During 2005, we experienced significant increases in natural gas costs which increased our
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Table of Contentsworking capital requirements for natural gas in storage. The increased natural gas costs also led to an increase in accounts receivable as the cost of gas is recovered dollar for dollar in our natural gas revenues. During 2005, we also experienced increased deferred costs related to transmission costs and deferred fuel. We would not expect similar levels of deferred transmission costs in 2006 as we received a rate order in January 2006 which increased our recoveries of transmission costs by approximately $67.5 million per year. The deferred fuel costs related primarily to an extended outage at our nuclear plant, increased costs associated with problems in our vendors’ ability to deliver coal via the railroad system and costs related to the implementation of the MISO Midwest Market. During 2005, our cash taxes were lower than 2004 due to the ability to realize tax benefits on the sale of non-utility assets and accelerated tax depreciation on PWGS Unit 1. Cash provided by operating activities increased to $599.0 million during 2004 compared with $528.9 million during the same period in 2003. This increase was due in large part to stronger cash earnings (net earnings plus non-cash valuation charges) as well as improvements in working capital. Investing Activities During 2005, we had $697.1 million of net cash outflows from investing activities. In 2004, we had net cash inflows from investing activities of $242.8 million and in 2003 we had net cash outflows of $595.2 million. In 2005, capital expenditures increased related to our Power the Future plan at We Power and for compliance with the consent decree entered into with the United States Environmental Protection Agency (EPA) (See Factors Affecting Results, Liquidity and Capital Resources — Environmental Matters). In addition, expenditures associated with nuclear fuel purchases were higher during 2005. In 2004, we recognized proceeds of $857.0 million for the sale of our manufacturing segment. The following table identifies capital expenditures by year:
We Power, which is included in the Non-Utility Energy segment, had capital expenditures of $275.1 million, $190.4 million and $162.9 million for the three years ended December 31, 2005, 2004 and 2003. In connection with our growth strategy which was announced in 2000, we have been focusing on divesting non-core assets and investing in core regulated assets. As a result, the sale of assets is a significant component of our investing activities. The following table identifies cash proceeds from asset sales:
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Table of ContentsFinancing Activities The following table summarizes our cash flows from financing activities:
During 2005, cash provided by financing activities was $157.8 million compared to $834.3 million of cash used for financing activities during 2004. In 2005, the primary uses of cash were to pay dividends on common stock and to purchase common stock to satisfy benefit plan obligations. In July 2005, PWGS issued $155.0 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature and have an average life approximating 15 years. The final payment is due July 15, 2030. Proceeds from the sale of the senior notes were used primarily to repay short-term debt incurred during construction at PWGS. For further information, see Note E — Port Washington Generating Station in the Notes to Consolidated Financial Statements. Wisconsin Gas retired at the scheduled maturity date $65 million of 6-3/8% Notes due November 1, 2005. In November 2005, Wisconsin Gas issued $90 million of 5.90% Debentures due December 1, 2035. The securities were issued under shelf registration statements filed with the SEC. The proceeds from the sale were used to repay a portion of our outstanding commercial paper. The commercial paper was incurred to both retire the $65 million of 6-3/8% Notes and for working capital requirements. During 2004, the proceeds from asset sales as well as improved cash flows from operations allowed us to retire $654.2 million of debt, including $200 million of 6.85% Trust Preferred Securities and $300 million of 5.875% senior notes due April 1, 2006. In September 2000, the Board of Directors amended the common stock repurchase program to authorize us to purchase up to $400 million of our shares of common stock in the open market. In March 2004, we announced that under this plan we would resume purchasing approximately $50 million of our common shares in the open market with the proceeds from the sale of the manufacturing business, which was effective July 31, 2004. During 2004, we purchased approximately 1.6 million shares of common stock for $50.4 million under this plan. We ceased repurchasing shares in October 2004. The program expired in December 2004. Over the life of the plan we repurchased and retired 14.9 million shares at a cost of $344.0 million. No new shares of common stock were issued in 2005. During January and February 2004, we issued approximately 0.2 million new shares of common stock in connection with our dividend reinvestment plan and various employee benefit plans. In 2003, we issued approximately 2.7 million new shares of common stock in connection with these plans. In 2004 and 2003, we received payments aggregating $4.8 million and $62.9 million, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the independent plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2005 and 2004, our plan agents purchased 2.0 million shares at a cost of $75.1 million and 3.2 million shares at a cost of $102.3 million, respectively, to fulfill exercised stock options. In 2005, we received proceeds of $47.0 million related to the exercise of stock options compared with $66.1 million in 2004. Prior to February 2004, we issued new shares to fulfill these obligations. CAPITAL RESOURCES AND REQUIREMENTS In 2000, we announced a growth strategy which, among other things, called for us to sell non-core assets and reduce our debt levels. Our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 59.5% at December 31, 2005 due primarily to asset sales. Over the next several years, we expect to have some limited asset sales, but at levels significantly lower than the previous six year level. In 2002, we initiated the construction of the first of our four planned generating units under our Power the Future program. The first unit at PWGS was completed and placed into service in July 2005. We expect to spend approximately $1.9 billion to complete construction of the remaining three generating units. Over the next several years, we expect to fund these plants with cash from operations and debt offerings.
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Table of ContentsCapital Resources We anticipate meeting our capital requirements during 2006 and the next several years 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 have access to 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 believe that we have adequate capacity to fund our operations for the foreseeable future through our borrowing arrangements and internally generated cash. In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, Wisconsin Electric filed an application with the PSCW that sought authority to issue up to $500 million of environmental trust bonds pursuant to this legislation. In October 2004, the PSCW approved an order authorizing Wisconsin Electric to issue environmental trust bonds to finance the recovery of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. We will continue to evaluate the potential issuance of environmental trust bonds. Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company’s obligations with respect to commercial paper. As of December 31, 2005, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $456.3 million of total consolidated short-term debt outstanding. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities at December 31, 2005:
Each of these facilities may be extended for an additional 364 days beyond the date of expiration, subject to lender agreement. We are currently in the process of renewing Wisconsin Energy’s $300 million credit facility which expires on April 8, 2006. In addition, we are also reviewing the possibility of amending and extending the other existing Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit facilities. The following table shows our consolidated capitalization structure at December 31:
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Table of ContentsAs described in Note J — Common Equity in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations. Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and the debt securities and preferred stock of our subsidiaries by Standard & Poors Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch as of December 31, 2005.
On March 29, 2005, S&P affirmed the security ratings of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas and changed the security ratings outlook from stable to negative for all three companies. The security rating outlooks assigned by Moody’s and Fitch for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are all stable. In March 2003, S&P lowered its corporate credit ratings for us from A- to BBB+ and for Wisconsin Electric and Wisconsin Gas, both from A to A-. S&P lowered its ratings for our senior unsecured debt from A- to BBB+; for Wisconsin Electric’s senior secured debt from A to A- and for Wisconsin Gas’ senior unsecured debt from A to A-. S&P affirmed Wisconsin Electric’s A- senior unsecured debt rating. S&P lowered the rating for our preferred stock from BBB to BBB- and for Wisconsin Electric’s preferred stock from BBB+ to BBB. S&P affirmed the A-2 short-term rating of us and lowered the short-term ratings of both Wisconsin Electric and Wisconsin Gas from A-1 to A-2. Wisconsin Electric’s senior secured and senior unsecured debt are both rated A- by S&P. S&P assigned a stable outlook. In October 2003, Moody’s downgraded certain of our security ratings and the security ratings of our subsidiaries. Moody’s lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A2 to A3 and our commercial paper rating from P-1 to P-2. Moody’s lowered Wisconsin Electric’s senior secured debt rating from Aa2 to Aa3, senior unsecured debt rating from Aa3 to A1 and preferred stock rating from A2 to A3. Moody’s lowered Wisconsin Gas’ senior unsecured debt rating from Aa2 to A1. Moody’s confirmed the P-1 commercial paper ratings of Wisconsin Electric and Wisconsin Gas. In February 2004, Moody’s changed the rating outlook for Wisconsin Energy and Wisconsin Energy Capital Corporation to stable from negative. In October 2003, Fitch downgraded certain of our security ratings and the security ratings of our subsidiaries. Fitch lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A to A- and the commercial paper rating of Wisconsin Energy from F1 to F2. Fitch lowered Wisconsin Electric’s senior secured debt rating from AA to AA-, senior unsecured rating from AA- to A+ and preferred stock rating from AA- to A. Fitch lowered Wisconsin Gas’ senior unsecured debt rating from AA- to A+. Fitch lowered the commercial paper ratings of Wisconsin Electric and Wisconsin Gas from F1+ to F1. We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
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Table of ContentsCapital Requirements Our current estimated 2006, 2007 and 2008 capital expenditures, excluding the purchase of nuclear fuel, are as follows:
Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact our utility energy segments, future long-term capital requirements may vary from recent capital requirements. Our estimated capital requirements through 2010 for Power the Future include approximately $2.6 billion to construct 2,120 megawatts of new natural gas-fired and coal-fired generating capacity of which we have expended approximately $673.9 million through the end of 2005. In the fourth quarter of 2005, we completed the sale of approximately a 17% interest (200 megawatts) in the Oak Creek expansion to two parties, at which time we received approximately $34.6 million in cash. The co-owners will share ratably in the construction costs. Total output of all four units, including the two unaffiliated entities’ portion, is 2,320 megawatts. We expect the capital requirements to support our investment in new generation under Power the Future to come from a combination of internal and external sources. We Power, a non-utility subsidiary, is constructing the new generating plants, which will be leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates. In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 to 200-megawatts at a cost in the range of $250 to $320 million. We anticipate the cost to build the wind farm projects would be recovered in our rates. We plan to file the necessary regulatory and environmental applications in 2006. We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals. Investments in Outside Trusts: We have funded our pension obligations, certain other post-retirement obligations and future nuclear obligations in outside trusts. Collectively, these trusts had investments that exceeded $1.9 billion as of December 31, 2005. These trusts hold investments that are subject to the volatility of the stock market and interest rates. For further information see Note O — Benefits in the Notes to Consolidated Financial Statements. Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note P — Guarantees in the Notes to Consolidated Financial Statements. We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by Financial Accounting Standard Board (FASB) Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases as reflected in the table below. We have included our contractual obligations under all three of these contracts in our Contractual Obligations/Commercial Commitments disclosure that follows. For additional information, see Note G — Variable Interest Entities in the Notes to Consolidated Financial Statements.
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Table of ContentsContractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2005:
Obligations for utility operations by our utility affiliates have historically been included as part of the rate making process and therefore are generally recoverable from customers. For a discussion of 2006, 2007 and 2008 estimated capital expenditures, see Capital Requirements above. FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES MARKET RISKS AND OTHER SIGNIFICANT RISKS We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to: Construction Risk: In December 2002, the PSCW issued a written order granting a CPCN to commence construction of the PWGS consisting of two 545-megawatt natural gas-fired combined cycle generating units on the site of Wisconsin Electric’s existing Port Washington Power Plant. The order approved key financial terms of the leased generation contracts including fixed construction costs of the PWGS at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate, force majeure, excused events and event of loss provisions. For additional information, see Power the Future — Port Washington below. In addition, in November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615-megawatt super critical pulverized coal generating units (Oak Creek expansion) adjacent to the site of Wisconsin Electric’s existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including a target construction cost of the Oak Creek expansion of $2.191 billion, plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see Power the Future — Oak Creek Expansion below. Large construction projects of this type are subject to usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, continuing legal challenges to permits obtained, changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, governmental actions and events in the global economy.
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Table of ContentsIf final costs for the construction of PWGS exceed the fixed costs allowed in the PSCW order, absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from Wisconsin Electric. If final costs of the Oak Creek expansion are within 5% of the target cost, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions. Regulatory Recovery Risk: The electric operations of Wisconsin Electric burn natural gas in its leased power plants, in several of its peaking power plants and as a supplemental fuel at several coal-fired plants. In addition, the cost of purchased power is generally tied to the cost of natural gas. Wisconsin Electric bears regulatory risk for the recovery of these fuel and purchased power costs when these costs are higher than the base rate established in its rate structure. As noted below in Commodity Price Risk, the electric operations of Wisconsin Electric operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for fuel and purchased power costs associated with the generation and delivery of electricity. Since our merger with WICOR in 2000 through December 31, 2005, we were allowed to request recovery of fuel and purchased power costs from retail electric customers in the Wisconsin jurisdiction through our rate review process with the PSCW and in interim fuel cost hearings when such annualized costs were expected to be more than 3% higher than the forecasted costs used to establish rates. In January 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis for 2006 to Wisconsin ratepayers and any under-collection will be subject to a 2% band. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for under- and over- collection within a 2% band. For 2005, 2004 and 2003, actual net fuel and purchased power costs at Wisconsin Electric exceeded fuel costs included in rates by $35.6 million, $0.8 million and $7.6 million, respectively. Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. Under SFAS 71, we record these items as regulatory liabilities. Commodity Price Risk: In the normal course of business, our utility and non-utility power generation subsidiaries utilize contracts of various duration for the forward sale and purchase of electricity. This is done to optimize utilization of their available generating capacity and energy during periods when available power resources are projected to be greater than or less than our load obligations. This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. In addition, effective April 1, 2005, our electric utilities became market participants in the MISO Midwest Market. For additional information on the MISO Midwest Market see Utility Rates and Regulatory Matters — Other Utility Rate Matters and Industry Restructuring and Competition — Electric Transmission and Energy Markets below. 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, uranium, natural gas and fuel oil. In addition, we manage our natural gas price risk by utilizing a gas hedging program. In July 2005, we received a letter from Union Pacific Corporation notifying us that a force majeure event requiring maintenance on a Union Pacific railroad line was expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of our coal generating facilities from June 2005 through November 2005. In response, we reduced generation at certain coal fueled units, primarily during lower cost off peak periods, to conserve coal inventories. This required us to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not expect to defer any additional costs related to this matter. Wisconsin’s retail electric fuel cost adjustment procedure mitigates some of Wisconsin Electric’s risk of electric fuel cost fluctuation. If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted, subject to risks associated with the regulatory approval process including regulatory lag. Regulatory lag risk occurs between the time we incur costs in excess of what we collect in rates, and the time we receive approval for interim rates following a regulatory filing. Regulatory risk can increase or
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Table of Contentsdecrease due to many factors which may also change during this approval period including commodity price fluctuations, unscheduled operating outages or unscheduled maintenance. In 2002, the PSCW authorized the inclusion of price risk management financial instruments for the management of our electrical utility gas costs. During 2003, a gas hedging program was approved by the PSCW and implemented by Wisconsin Electric. The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for the gas utility operations of Wisconsin Electric and Wisconsin Gas through gas cost recovery mechanisms, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment procedure and the natural gas utilities’ gas cost recovery mechanisms, see Utility Rates and Regulatory Matters below. Natural Gas Costs: Significant increases in the cost of natural gas affect our electric and gas utility operations. Natural gas costs have increased significantly, both because the supply of natural gas in recent years has not kept pace with the demand for natural gas and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas is added to the nation’s energy supply mix. Higher natural gas costs increase our working capital requirements and result in higher gross receipts taxes in the State of Wisconsin. Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Because federal and state energy assistance dollars have not kept pace with rising natural gas costs, our risks related to bad debt expenses associated with non-paying customers has increased. In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. In 2004 and 2003, we had approval from the PSCW to defer residential bad debt net write-offs that exceed amounts allowed in rates. As a result of gas cost recovery mechanisms, our gas distribution subsidiaries receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. In addition, we are experiencing reduced usage of natural gas by our residential customers, who contribute higher margins than other customer classes, due to the increased natural gas costs. We expect to continue to experience this reduced usage during the 2006 winter heating season. Weather: The rates of Wisconsin Electric and Wisconsin Gas are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric’s electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. The gas revenues of Wisconsin Electric and Wisconsin Gas 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 2005, 2004 and 2003, as measured by degree-days, may be found above in Results of Operations. Interest Rate Risk: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2005. Borrowing levels under these arrangements vary from period to period depending upon capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels. We performed an interest rate sensitivity analysis at December 31, 2005 of our outstanding portfolio of $456.3 million of short-term debt with a weighted average interest rate of 4.39% and $189.8 million of variable-rate long-term debt with a weighted average interest rate of 3.77%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $4.6 million before taxes from short-term borrowings and $1.9 million before taxes from variable rate long-term debt outstanding. Marketable Securities Return Risk: We fund our pension, other post-retirement benefit and nuclear decommissioning obligations through various trust funds, which in turn invest in debt and equity securities. Changes in the market price of the assets in these trust funds can affect future pension, other post-retirement benefit and nuclear decommissioning expenses. Future contributions to these trust funds can also be affected by changes in the market price of trust fund assets. We expect that the risk of expense and contribution variations as a result of changes in the market price of trust fund assets would be mitigated in part through future rate actions by our various utility regulators. Through December 31, 2005, we were operating under a PSCW-ordered, qualified five-year rate restriction period. For further information about the rate restriction, see Utility Rates and Regulatory Matters below.
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Table of ContentsAt December 31, 2005, we held the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.
Fiduciary oversight of the pension and other post-retirement plan trust fund investments is the responsibility of an Investment Trust Policy Committee. Qualified external investment managers are engaged to manage the investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor. The current study for the pension fund projects long-term, annualized returns of approximately 8.5%. Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the Investment Trust Policy Committee. Qualified external investment managers are also engaged to manage these investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor, subject to additional constraints established by the PSCW. The current study projects long-term, annualized returns of approximately 9%. Current PSCW constraints allow a maximum allocation of 65% in equities. Wisconsin Electric insures various property and outage risks through Nuclear Electric Insurance Limited (NEIL). Annually, NEIL reviews its underwriting and investment results and determines the feasibility of granting a distribution to policyholders. Adverse loss experience, rising reinsurance costs or impaired investment results at NEIL could result in increased costs or decreased distributions to Wisconsin Electric. 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 and energy services contracts and employee benefit plans that could require, in the event of a credit ratings change to below investment grade, a termination payment if collateral is not provided or an accelerated payment. At December 31, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $78.2 million. Economic Risk: We are exposed to market risks in the regional midwest economy for our utility energy segment. Inflationary Risk: We continue to monitor the impact of inflation, especially with respect to the rising costs of medical plans, in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. Except for continuance of an increasing trend in the inflation of medical costs and the impacts on our medical and post-retirement benefit plans, we have expectations of low-to-moderate inflation. We do not believe the impact of general inflation will have a material effect on our future results of operations. For additional information concerning risk factors, including market risks, see Cautionary Factors below. POWER THE FUTURE Under our Power the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. We Power will lease the new plants to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates. Power the Future - Port Washington Background: In December 2002, the PSCW issued a written order (the Port Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of the PWGS consisting of two 545-megawatt natural gas-fired combined cycle generating units (PWGS Units 1 and 2) on the site of Wisconsin Electric’s existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral, which was completed in December 2004, and American Transmission Company LLC (ATC) to construct required transmission system upgrades to serve PWGS Units 1 and 2 as a result of their concurrent applications. PWGS Unit 1 was completed in July 2005 and placed into service at that time. Unit 1 was completed within the PSCW approved cost parameters. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional transmission
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Table of Contentsrelated assets from We Power to Wisconsin Electric. We Power began site preparation of Unit 2 in May 2004. We expect Unit 2 to be operational in 2008. Lease Terms: The PSCW approved the lease agreements and related documents under which Wisconsin Electric will staff, operate and maintain PWGS Units 1 and 2. Key terms of the leased generation contracts include:
In January 2003, Wisconsin Electric filed a request with the PSCW to defer costs for recovery in future rates. The PSCW approved the request in an open meeting in April 2003. We Power began collecting certain costs from Wisconsin Electric in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. We defer the lease costs on our balance sheet, and we amortize the costs to expense as we recover the costs in rates. Legal and Regulatory Matters: There are currently no legal challenges to the construction of the PWGS and all construction permits have been received for Units 1 and 2. As a result of the enactment of the Energy Policy Act of 2005 (the Energy Policy Act) the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC’s jurisdiction. Under the FERC’s recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the remaining PWGS unit prior to the unit being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any. Power the Future - Oak Creek Expansion Background: In November 2003, the PSCW issued an order (the Oak Creek Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of two 615-megawatt coal-fired units (the Oak Creek expansion) to be located adjacent to the site of Wisconsin Electric’s existing Oak Creek Power Plant. We anticipate the first unit will be operational in 2009 and the second unit will be operational in 2010. The Oak Creek Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the State. The total cost for the two units was set at $2.191 billion, and the order provided for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW. The CPCN was granted contingent upon us obtaining the necessary environmental permits. All necessary permits have been received at this time. In June 2005, construction commenced at the site. In November 2005, we completed the sale of approximately a 17% interest in the project to two unaffiliated entities, who will share ratably in the construction costs. Lease Terms: In October 2004, the PSCW approved the lease generation contracts between Wisconsin Electric and We Power for the Oak Creek expansion. Key terms of the leased generation contracts include:
In April 2004, the PSCW approved the deferral of certain costs related to the Oak Creek expansion for recovery in future rates. (See Limited Rate Adjustment Request below for further information).
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Table of ContentsLegal and Regulatory Matters: The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. We have received all permits necessary to commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge. The major permits are discussed below. In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW’s order authorizing us to build two coal-fired generating facilities on the site of our existing Oak Creek Power Plant vacated the CPCN and remanded it back to the PSCW for additional proceedings. The Court determined that the PSCW committed errors in determining the completeness of our application and in its decisions on several other points. The Dane County Circuit Court’s decision was appealed and in June 2005, the Supreme Court of Wisconsin issued its decision which reversed the Dane County Circuit Court’s decision that vacated the PSCW order authorizing us to build the Oak Creek expansion and upheld the PSCW’s order in all respects. The CPCN granted by the PSCW was reinstated and is in full force and effect. As a result of the delay to the start of construction caused by litigation, the project cost is expected to increase by $50 to $55 million. This represents an increase of approximately 2.4% to 2.6% in the total cost of the project. We believe these costs are ultimately recoverable under the terms of the lease agreements between We Power and Wisconsin Electric. However, recovery is subject to our final calculation of costs and also to review and approval by the PSCW. In September 2003, several parties filed a request with the Wisconsin Department of Natural Resources (WDNR) for a contested case hearing in connection with our application to the WDNR for a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Oak Creek expansion. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and in November 2004, the administrative law judge approved the WDNR’s issuance of the Chapter 30 permit for the Oak Creek expansion. In December 2004, opponents filed a petition for review of the decision in Dane County Circuit Court. In January 2005, we filed a motion to dismiss the opponents’ petition based on procedural errors. The WDNR joined in this motion. In March 2005, the court dismissed the appeal. The opponents appealed the court’s dismissal to the Wisconsin Court of Appeals. In February 2006, the Wisconsin Court of Appeals affirmed the lower court’s dismissal of the case. The opponents can seek reconsideration of the court’s decision or can petition the Wisconsin Supreme Court for review. We applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit that is required for operation of the water intake and discharge system for the planned Oak Creek expansion and existing Oak Creek generating units. In March 2005, the WDNR determined that the proposed cooling water intake structure and water discharge system meets regulatory requirements and reissued the WPDES permit with specific limitations and conditions. The opponents filed a petition for judicial review in Dane County Circuit Court and a request for a contested case proceeding with the WDNR. In September 2005, the judicial review proceeding in Dane County Circuit Court was dismissed. All parties to this action agreed to the dismissal. The WDNR granted a contested case hearing and the administrative law judge has scheduled a hearing for March 2006. We anticipate a decision by the administrative law judge in 2006. In May 2005, we received the Army Corps of Engineers federal permit necessary for the construction of the Oak Creek expansion. Opponents may appeal the permit in federal court. In January 2004, the WDNR issued the Air Pollution Control Construction Permit (Air Permit) to Wisconsin Electric for the Oak Creek expansion. The permit was opposed and a contested case hearing with the WDNR was held in October 2004. In February 2005, an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Permit. The decision was opposed and project opponents filed a petition for judicial review with the Dane County Circuit Court. In September 2005, the Dane County Circuit Court dismissed with prejudice the appeal of the administrative law judge’s decision. All parties to this action agreed to the dismissal. This dismissal is the final resolution of all legal challenges to the issuance of the Air Permit. In addition, as a result of the enactment of the Energy Policy Act the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC’s jurisdiction. Under the FERC’s recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the two units that are part of the Oak Creek expansion prior to the units being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any.
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Table of ContentsUTILITY RATES AND REGULATORY MATTERS The PSCW regulates our retail electric, natural gas, steam and water rates in the State of Wisconsin, while the FERC regulates wholesale power, electric transmission and interstate gas transportation service rates. The Michigan Public Service Commission (MPSC) regulates retail electric rates in the State of Michigan. Within our regulated segment, we estimate that approximately 87% of our electric revenues are regulated by the PSCW, 8% are regulated by the MPSC and the balance of our electric revenues are regulated by the FERC. All of our natural gas 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/. Overview: For the period from March 2000 until December 31, 2005, the rates of We Energies (the trade name of Wisconsin Electric and Wisconsin Gas) were governed by an order from the PSCW in connection with the approval of the WICOR acquisition. Under this order, We Energies was restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions. Wisconsin Electric: In July 2005, we filed an electric and steam price increase request with the PSCW. Under a limited rate proceeding, we requested an increase in electric rates of $143.6 million for 2006, and an $8.8 million total increase in rates for steam over the two year period of 2006 and 2007. The requested electric rate increase included: (1) costs associated with the continued investment in our Power the Future strategy; (2) recovery of transmission costs incurred that exceed the amount we are currently collecting from customers; (3) additional sources of renewable energy; and (4) a rate freeze for day to day operations of the electric system until 2008. The requested steam rate increase was due to (1) the costs of maintaining the steam system, (2) the cost of fuel and (3) the costs associated with making changes to our steam utility operations as part of the reconstruction of the Marquette Interchange project in downtown Milwaukee, Wisconsin. Subsequent to the initial filing of this pricing request, we experienced a significant increase in the cost of fuel and purchased power due to the increases in natural gas prices and the reductions in coal deliveries as discussed above. In October 2005, we filed a letter with the PSCW informing them of our need to include the increased cost of natural gas used for generation of electricity in our pending 2006 pricing request. The PSCW considered these additional costs and approved an increase in electric rates of $222.0 million in January 2006. In addition, the PSCW approved an increase in steam rates of $7.8 million or 31.5% to be phased in over the two year period of 2006 and 2007. These rate increases became effective on January 26, 2006 and we anticipate will remain in effect through December 2007. The January 2006 order also addressed Wisconsin Electric’s under- and over-collection of fuel costs in its electric rates. For 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis to ratepayers and the band for under-collection of fuel costs will be 2%. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction with a plus or minus 2% band. In June 2005, we filed with the PSCW a natural gas price increase request of $27.4 million for Wisconsin Electric. The increase was requested to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we received approval from the PSCW for a rate increase of $21.4 million or 2.9% for Wisconsin Electric. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007. The January 2006 order approved a return on equity for Wisconsin Electric operations of 11.2%. In 2005, Wisconsin Electric’s approved return on equity was 12.2%.
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Table of ContentsThe table below summarizes the anticipated annualized revenue impact of recent rate changes.
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