SCHEDULE 14A

SCHEDULE 14A INFORMATION

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:

[   ]      Preliminary Proxy Statement

[   ]      Confidential, for Use of the             Commission Only (as permitted             by Rule 14a-6(e)(2))

[X]      Definitive Proxy Statement

[   ]      Definitive Additional Materials

[   ]      Soliciting Material Pursuant to Rule 14a-11(c) or Rule 14a-12

OGE ENERGY CORP.

(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):

[X]      No fee required

[   ]      Fee Computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11.

1)		Title of each class of securities to which transaction applies:
2)		Aggregate number of securities to which transaction applies:
3)		Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined):
4)		Proposed maximum aggregate value of transaction:
5)		Total fee paid:

[   ]      Fee paid previously with preliminary materials.

[   ]      Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

1)		Amount Previously Paid:
2)		Form, Schedule or Registration Statement No.:
3)		Filing Party:
4)		Date Filed:

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Contents

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March 30, 2007

 

 

Dear Shareowner:

 

You are cordially invited to attend the annual meeting of OGE Energy Corp. at 10:00 a.m. on Thursday, May 17, 2007, at the National Cowboy and Western Heritage Museum, 1700 Northeast 63rd Street, Oklahoma City, Oklahoma.

 

The matters to be voted on at the meeting are described in the Notice of Annual Meeting of Shareowners and Proxy Statement on the following pages.

 

Even though you may own only a few shares, your proxy is important in making up the total number of shares necessary to hold the meeting. Whether or not you plan to attend the meeting, please vote your shares as soon as possible. A return envelope for your proxy card is enclosed for your convenience. Again this year, in addition to telephone voting, you also have the option of voting by the Internet. Instructions are included on the proxy card. Your vote will be appreciated.

 

Those arriving before the meeting will have the opportunity to visit informally with the management of your Company. In addition to the business portion of the meeting, there will be reports on our current operations and outlook.

 

Your continued interest in the Company is most encouraging and, on behalf of the Board of Directors and employees, I want to express our gratitude for your confidence and support.

 

 

 

 

 

 

(ii)

 

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Notice of Annual Meeting

of Shareowners

 

The Annual Meeting of Shareowners of OGE Energy Corp. will be held on Thursday, May 17, 2007, at 10:00 a.m. at the National Cowboy and Western Heritage Museum, 1700 Northeast 63rd Street, Oklahoma City, Oklahoma, for the following purposes:

 

 

 

 

 

The map on page 34 will assist you in locating the National Cowboy and Western Heritage Museum.

 

Shareowners who owned stock on March 20, 2007, are entitled to notice of and to vote at this meeting or any adjournment of the meeting. A list of such shareowners will be available, as required by law, at our principal offices at 321 North Harvey, Oklahoma City, Oklahoma 73102.

 

 

 

 

Dated: March 30, 2007

 

IMPORTANT — YOUR PROXY CARD IS ENCLOSED IN THIS ENVELOPE

 

To assure your representation at the meeting, please vote your shares by the Internet, by telephone or by signing, dating and returning the proxy card promptly in the enclosed envelope. No postage is required for mailing in the United States. If your shares are held in the name of a broker, trust, bank or other nominee and you plan to attend the meeting and vote your shares in person, you should bring with you a proxy or letter from the broker, trustee, bank or other nominee confirming your beneficial ownership of the shares.

 

 

(iii)

 

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Proxy Statement

 

March 30, 2007

Introduction

 

The Annual Meeting of Shareowners of OGE Energy Corp. (the “Company”) will be held at the National Cowboy and Western Heritage Museum, 1700 Northeast 63rd Street, Oklahoma City, Oklahoma, on May 17, 2007, at 10:00 a.m. For the convenience of those shareowners who may attend the meeting, a map is printed on page 34 that gives directions to the National Cowboy and Western Heritage Museum. At the meeting, we intend to present the first two items in the accompanying notice for action by the owners of the Company’s Common Stock. The Board of Directors does not now know of any other matters to be presented at the meeting, but, if any other matters are properly presented to the meeting for action, the persons named in the accompanying proxy will vote upon them in accordance with their best judgment.

 

Your Board of Directors is sending you this proxy statement in connection with the solicitation of your proxy for use at the Annual Meeting. When you vote by Internet, by telephone or by mail, you appoint Steven E. Moore, H. H. Champlin and Robert Kelley as your representatives at the Annual Meeting. Mr. Moore, Mr. Champlin and Mr. Kelley will vote your shares, as you have instructed them, at the Annual Meeting. This way, your shares will be voted whether or not you attend the Annual Meeting. Even if you plan to attend the meeting, it is a good idea to vote your shares in advance of the meeting, just in case your plans change.

 

If an issue comes up for vote at the meeting that is not on the proxy card, Mr. Moore, Mr. Champlin and Mr. Kelley will vote your shares, under your proxy, in accordance with their best judgment.

 

Voting Procedures; Revocation of Proxy

 

You may vote by mail, by telephone, by Internet, or in person. To vote by mail, simply complete and sign the proxy card and mail it in the enclosed, prepaid and preaddressed envelope. If you mark your voting instructions on the proxy card, your shares will be voted as you instruct. If you return a signed card but do not provide voting instructions, your shares will be voted FOR the four named nominees for director and FOR the ratification of Ernst & Young LLP as the Company’s principal independent accountants.

 

Shareowners of record also may vote by the Internet or by using the toll-free number listed on the proxy card. Telephone and Internet voting also is available to shareowners who hold their shares in the Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”) and the OGE Energy Corp. Employees’ Stock Ownership and Retirement Savings Plan (the “Retirement Savings Plan”). The telephone voting and Internet voting procedure is designed to verify shareowners through use of a number that is provided on each proxy card. This procedure allows you to vote your shares and to confirm that your instructions have been properly recorded. If you vote by telephone or by the Internet, you do not have to mail in your proxy card. Please see your proxy card for specific instructions.

 

If you wish to vote in person, we will pass out written ballots at the meeting. If you hold your shares in street name (i.e., they are held by your broker in an account for you), you must request a legal proxy from your broker in order to vote at the meeting.

 

If you change your mind after voting your proxy, you can revoke your proxy and change your vote at any time before the polls close at the meeting. You can revoke your proxy by either signing another proxy with a later date, by voting by Internet, by telephone or by voting at the meeting. Alternatively, you may provide a written statement to the Company (attention Carla D. Brockman, Vice President - Administration and Corporate Secretary) of your intention to revoke your proxy.

 

Record Date; Number of Votes

 

If you owned shares of our Common Stock at the close of business on March 20, 2007, you are entitled to one vote per share upon each matter presented at the meeting.

 

On March 1, 2007, there were 91,568,663 shares of Common Stock outstanding. The Company does not have any other outstanding class of voting stock. No person holds of record or, to our knowledge, beneficially owns more than 5% of our Common Stock.

 

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Expenses of Proxy Solicitation

 

We will pay all costs associated with preparing, assembling and mailing the proxy cards and proxy statements. We also will reimburse brokers, nominees, fiduciaries and other custodians for their expenses in forwarding proxy materials to shareowners. Officers and other employees of the Company may solicit proxies by mail, personal interview, telephone, Internet and/or telegraph. In addition, we have retained Mellon Investor Services to assist in the solicitation of proxies, at a fee of approximately $7,500 plus associated costs and expenses. Our employees will not receive any additional compensation for soliciting proxies.

 

Mailing of Proxy Statement and Annual Report

 

This proxy statement and the enclosed proxy were mailed on or about March 30, 2007. Appendix A to this proxy statement includes our audited financial statements and management’s discussion and analysis of financial condition and results of operations. This Appendix A and our Summary Annual Report, which contains Mr. Moore’s letter to shareowners, condensed financial statements and a summary discussion of results of operations, were mailed with this proxy statement on or about March 30, 2007, to all of our shareowners who owned stock on March 20, 2007.

 

Voting Under Plans

 

If you are a participant in our DRIP/DSPP, your proxy will represent the shares held on your behalf under the DRIP/DSPP and such shares will be voted in accordance with the instructions on your proxy. If you do not vote your proxy, your shares in the DRIP/DSPP will not be voted.

 

If you are a participant in our Retirement Savings Plan, you will receive a voting directive for shares allocated to your account. The trustee will vote these shares as instructed by you in your voting directive. If you do not return your voting directive, the trustee will vote your allocated shares in the same proportion that all plan shares are voted.

 

Voting of Shares Held in Street Name by Your Broker

 

Brokerage firms have authority under New York Stock Exchange Rules to vote customers’ unvoted shares on certain “routine” matters, including the election of directors and ratification of the auditors. If you do not vote your proxy, your brokerage firm may either vote your shares on routine matters or leave your shares unvoted. We encourage you to provide instructions to your brokerage firm by voting your proxy. This ensures your shares will be voted at the meeting. When a brokerage firm votes its customers’ unvoted shares on routine matters, these shares are counted for purposes of establishing a quorum to conduct business at the meeting. A brokerage firm, however, cannot vote customers’ shares on non-routine matters. Accordingly, these shares (sometimes referred to as broker non-votes) are considered not entitled to vote on non-routine matters, rather than as a vote against the matter.

 

PROPOSAL NO. 1 -

ELECTION OF DIRECTORS

 

The Board of Directors of the Company presently consists of ten members. The directors are classified into three groups. One class of directors is elected at each year’s Annual Meeting for a three-year term and to continue in office until their successors are elected and qualified. The following four persons are the nominees of the Board to be elected for such three-year term at the Annual Meeting to be held on May 17, 2007: Mr. Luke R. Corbett, Mr. Peter B. Delaney, Mr. Robert Kelley and Mr. J.D. Williams. Each of these individuals is currently a director of the Company whose term as a director is scheduled to expire at the Annual Meeting. In addition, each of these individuals, as well as each other director of the Company during 2006, also was a director of the Company’s principal subsidiary, Oklahoma Gas and Electric Company (“OG&E”).

 

The enclosed proxy, unless otherwise specified, will be voted in favor of the election as directors of the previously listed four nominees. The Board of Directors does not know of any nominee who will be unable to serve, but if any of them should be unable to serve, the proxy holder may vote for a substitute nominee. No nominee or director owns more than 1.2% of any class of voting securities of the Company.

 

For the nominees described herein to be elected as directors, they must receive the affirmative vote of the holders of a majority of the votes of shares of Common Stock present in person or by proxy and entitled to vote. Withholding authority is treated as a vote against.

 

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INFORMATION ABOUT DIRECTORS AND NOMINEES

 

Nominees for Election for Term Expiring at 2010 Annual Meeting of Shareowners

 

 

 

 

 

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Directors Whose Terms Expire at 2009 Annual Meeting of Shareowners

 

 

 

 

 

 

 

 

 

 

 

 

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Directors Whose Terms Expire at 2008 Annual Meeting of Shareowners

 

 

 

 

 

The affirmative vote of the holders of a majority of the shares of Common Stock present in person or by proxy and entitled to vote at the Annual Meeting will be required for the election of the four nominees as director. Withholding authority is treated as a vote against.

 

The Board of Directors recommends a vote “FOR” the election of the four nominees as director. Proxies solicited by the Board of Directors will be voted “FOR” the election of the four nominees as director, unless a different vote is specified.

 

 

 

 

 

 

 

 

 

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INFORMATION CONCERNING THE BOARD OF DIRECTORS

 

General. Each member of our Board of Directors other than Mr. Delaney was also a director of OG&E during 2006. The Board of Directors of the Company met on ten occasions during 2006 and the Board of Directors of OG&E met on seven occasions during 2006. Each director attended at least 85% of the total number of meetings of the Boards of Directors and the committees of the Boards on which he or she served.

Committees. The standing committees of the Company’s Board of Directors include a compensation committee, an audit committee and a nominating and corporate governance committee.

 

 

The members of the committees during 2006, the general functions of the committees and number of committee meetings in 2006 are set forth below.

 

 

 

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Corporate Governance

 

Corporate Governance Guidelines. The Board of Directors of the Company operates pursuant to a set of written Corporate Governance Guidelines that set forth the Company’s corporate governance philosophy and the governance policies and practices that the Company has established to assist in governing the Company and its affiliates. The Guidelines state that the primary mission of the Board of Directors of the Company is to advance the interests of the Company’s shareowners by creating a valuable long-term business.

 

The Guidelines describe Board membership criteria and the Board selection and member orientation process. The guidelines require that a majority of the directors must be independent and that members of each committee must be independent and state the Board’s belief that the chief executive officer (“CEO”) and the president should be the only Company executives serving as a director. Absent approval of the Nominating and Corporate Governance Committee, no director may be nominated to a new term if he or she would be older than 70 at the time of election. The Guidelines also provide that no director may serve on more than three other boards of directors of publicly-held companies without the prior approval of the Nominating and Corporate Governance Committee. Directors whose professional responsibilities change, such as upon retirement or a change in employer, are required to submit a letter of resignation for the Board’s consideration. The Guidelines provide that, except for employment arrangements with the CEO and the president, the Company will not engage in transactions with directors or their affiliates if such transactions would cast into doubt the independence of a director, present the appearance of a conflict of interest, or are otherwise prohibited by law, rule or regulation.

 

The Guidelines provide that the Compensation Committee of the Board will evaluate the performance of the CEO on an annual basis and that the Nominating and Corporate Governance Committee will report to the Board at least annually on succession planning, which will include appropriate contingencies in the event the CEO retires or is incapacitated. The Guidelines also provide that the Nominating and Corporate Governance Committee is responsible for overseeing an annual assessment of the performance of the Board and Board committees, as well as for reviewing with the Board the results of these assessments. All of these tasks were completed for 2006.

 

The Guidelines provide that Board members have full access to officers and employees of the Company and, as necessary and appropriate, the Company’s independent advisors, including legal counsel and independent accountants. The Guidelines further provide that the Board and each committee have the power to hire independent legal, financial or other advisors as they deem necessary. The Guidelines provide that the independent directors, which include all non-management directors, are to meet in executive session, generally coinciding with regularly scheduled Board meetings. In 2006, the independent directors met in executive session nine times.

 

Our Code of Conduct that is applicable to all of our directors, officers and employees, and the Corporate Governance Guidelines comply with the Sarbanes-Oxley Act of 2002 and the listing standards of the New York Stock Exchange. We also have a separate code of ethics that applies to our CEO and our senior financial officers, including, our chief financial officer and our chief accounting officer, and that complies with the requirements imposed by the Sarbanes-Oxley Act of 2002 and the rules issued thereunder for codes of ethics applicable to such officers. The Board has reviewed and will continue to evaluate its role and responsibilities with respect to the legislative and other governance requirements of the New York Stock Exchange. All of our corporate governance materials, including our codes of conduct and ethics, our Guidelines for Corporate Governance and all of our committee charters, are available for public viewing on the OGE Energy web site at www.oge.com under the heading Investors, Corporate Governance. Copies of our corporate governance material also are available without charge to shareowners who request them. Requests must be in writing and sent to: Corporate Secretary, OGE Energy Corp., 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321.

 

Director Independence. The Board of Directors of the Company currently has ten directors, eight of whom are independent within the meaning of the New York Stock Exchange listing standards. Our Chairman and CEO and our President are the only directors who are not considered independent. For purposes of determining independence, we have adopted the following standards for director independence in compliance with the listing standards of the New York Stock Exchange:

 

 

 

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service (provided such compensation is not contingent in any way on continued service), is not independent until three years after he or she ceases to receive more than $100,000 in any twelve-month period in such compensation;

 

 

 

 

 

 

 

For purposes of determining whether the directors met the aforementioned tests and should be deemed independent, the Board concluded that the purchase of electricity from OG&E at rates approved by a state utility commission does not constitute a material relationship. Based on this, the Board determined that each of the following members of the Board met the aforementioned independence standards: Herbert H. Champlin; Luke R. Corbett; John D. Groendyke; Robert Kelley; Linda Petree Lambert; Robert O. Lorenz; Ronald H. White, M.D. and J.D. Williams. Mr. Moore does not meet the aforementioned independence standards, because he is the current CEO and an employee of the Company. Mr. Delaney does not meet the aforementioned independence standards because he is the current President and Chief Operating Officer (“COO”) and an employee of the Company.

 

Standing Committees. The standing committees of the Board of Directors include - audit; compensation; and nominating and corporate governance. All members of these committees are independent directors who are nominated and approved by the Board each year. The roles and responsibilities of these committees are defined in the committee charters adopted by the Board and provide for oversight of, among other things, executive management. Each of these committee charters is available on our website at www.oge.com under the heading Investors, Corporate Governance. The duties and responsibilities of the Board committees are reviewed regularly and are outlined above.

 

Audit Committee Financial Expert. The Board has determined that Mr. Robert Kelley meets the Securities and Exchange Commission definition of audit committee financial expert.

 

Process Related to Executive Officer and Director Compensation. Under the terms of its charter, the compensation committee of the Board of Directors (the “Compensation Committee”) has broad authority to develop and implement the Company’s compensation policies and programs for executive officers and Board members. In particular the Compensation Committee is to:

 

 

 

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The Compensation Committee may, in its discretion, delegate all or a portion of its duties and responsibilities to a subcommittee or, to the extent permitted by applicable law, to any other body or individual. In particular, the Compensation Committee may delegate the approval of certain transactions to a subcommittee consisting solely of members of the Compensation Committee who are (a) “non-employee directors” within the meaning of Rule 16b-3 of the Securities Exchange Act of 1934, and (b) “outside directors” for the purpose of Section 162(m) of the Internal Revenue Code (the “Code”).

 

The process for setting director and executive compensation in 2006 involved numerous steps. In the late summer of 2005, senior management met with representatives of Towers Perrin, a nationally recognized compensation consulting firm engaged by the Compensation Committee, to discuss the Company’s existing executive compensation program and potential changes to the program or any of the underlying compensation plans. In September 2005, the Company’s Board of Directors received a presentation from Towers Perrin that included an annual review of director and executive compensation in the utility industry and an overview of trends and emerging issues in executive and board remuneration.

 

The next step in the process was an annual performance evaluation of each member of the management team. This process entailed for each member of the management team (other than the CEO) an objective scoring by such individual’s supervisor of various competencies, including the individual’s management skills, business knowledge and achievement of various performance and development objectives set at the beginning of the year. These reviews were used by the CEO and COO in making compensation recommendations to the Compensation Committee.

 

The balance of the process for setting director and executive compensation for 2006 involved actions taken by the Compensation Committee. The Compensation Committee met in November 2005, December 2005 and February 2006 to address 2006 compensation. At the November 2005 meeting, the Compensation Committee reviewed with the CEO and COO the performance evaluations of each member of management (other than the CEO), with the CEO giving his performance evaluation of the COO. The Compensation Committee at its November 2005 meeting also reviewed and discussed with the CEO and COO their recommendations for each member of management (other than the CEO) of 2006 salaries, target annual incentive awards (expressed as a percentage of salary) and target long-term incentive awards (also expressed as a percentage of salary). In addition, the Compensation Committee evaluated the CEO’s performance at its November 2005 meeting and discussed his potential salary, target annual incentive award and target long-term compensation for 2006. The meeting of the Compensation Committee in November 2005 concluded without any action by the Compensation Committee on these components of 2006 executive compensation. The Compensation Committee did review and set compensation for the directors, which is described below under “Director Compensation.”

 

At the Compensation Committee’s meeting in December 2005, the Compensation Committee met and set 2006 salaries and, subject to potential adjustment at its meeting in February 2006, target annual incentive awards and target long-term compensation awards for each member of management. The target annual incentive awards and target long-term compensation awards were expressed as percentages of salary. The Company performance goals that needed to be achieved for any payouts of annual incentive awards or long-term incentives were not set at this meeting; but, instead, were left for consideration at the scheduled meeting in February 2006.

 

Prior to the Compensation Committee’s meeting in February 2006, the Company’s senior management developed recommendations for the Company performance goals that needed to be met in order for any payouts of 2006 annual incentive awards or 2006 long-term compensation awards to occur.

 

 

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At this meeting in February 2006, the Compensation Committee reviewed with senior management its recommendations and basis for Company performance goals for payouts of 2006 annual incentive awards and long-term compensation awards. Following this discussion, the Compensation Committee set the 2006 Company performance goals for annual incentive awards and long-term compensation awards that had to be achieved in order for payouts of such awards to occur. The Compensation Committee also approved the form of the long-term compensation awards, which, like prior years, consisted entirely of performance units.

 

Lead Director. In an effort to strengthen independent oversight of management and to provide for more open communication, the Board has appointed Luke R. Corbett to serve in the role of lead director. The nonmanagement lead director chairs executive sessions of the Board conducted without management. These sessions will be held at least twice annually and were held nine times in 2006.

 

Communications with the Board of Directors. Shareowners and other interested parties who wish to communicate with members of the Board, including the independent directors individually or as a group, may send correspondence to them in care of the Corporate Secretary at the Company’s principal offices, 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321. We currently do not intend to have the Corporate Secretary screen this correspondence, but we may change this policy if directed by the Board due to the nature and volume of the correspondence.

 

The Company encourages each of its Board members to attend the Annual Meeting and the directors are expected to attend whenever reasonably possible. All of the Board members attended the Annual Meeting in 2006.

 

Prohibition on Loans. The Company’s Stock Incentive Plan prohibits all loans to executive officers.

 

Auditors; Audit Partner Rotation. As described on page 13, the Company is requesting that the shareowners ratify the selection of Ernst & Young LLP as the Company’s principal independent accountants for 2007. The Audit Committee charter provides that the audit partners will be rotated as required by Sarbanes-Oxley.

 

Stock Ownership Guidelines. During 2004, the Company established stock ownership guidelines for its directors and officers. The terms of these guidelines are explained on page 22 in Compensation Discussion and Analysis.

 

Shareowner Nominations for Directors. It is expected that the nominating and corporate governance committee will consider nominees recommended by shareowners in accordance with our By-laws. Our By-laws provide that, if you intend to nominate director candidates for election at an Annual Meeting of Shareowners, you must deliver written notice to the Corporate Secretary no later than 90 days in advance of the meeting. The notice must set forth certain information concerning you and the nominee(s), including each nominee’s name and address, a representation that you are entitled to vote at such meeting and intend to appear in person or by proxy at the meeting to nominate the person or persons specified in your notice, a description of all arrangements or understandings between you and each nominee and any other person pursuant to which the nomination or nominations are to be made by you, such other information as would be required to be included in a proxy statement soliciting proxies for the election of the nominee(s) and the consent of each nominee to serve as a director if so elected. The chairman of the Annual Meeting may refuse to acknowledge the nomination of any person not made in compliance with the foregoing procedure.

 

In considering individuals for nomination as directors, the nominating and corporate governance committee typically solicits recommendations from its current directors and is authorized to engage third party advisors, including search firms, to assist in the identification and evaluation of candidates.

 

The nominating and corporate governance committee has not established specific minimum qualities for director nominees or set forth specific qualities or skills that the nominating and corporate governance committee believes are necessary for one or more directors to possess. Instead, in evaluating potential candidates and incumbent directors for reelection, the nominating and corporate governance committee considers numerous factors, including judgment, skill, independence, integrity, experience with businesses and other organizations of comparable size, the interplay of the candidate’s experience with the experience of other Board members, experience as an officer or director of another publicly-held corporation, understanding of management trends in general or in industries relevant to the Company, expertise in financial accounting and corporate finance, ability to bring diversity to the group, community or civic service, appropriateness of having a member of management, in addition to the CEO, on the Board as part of the succession planning process, knowledge or expertise not currently on the Board, shareowner perception, and the extent to which the candidate would be a desirable addition to the Board and any

 

 

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committees of the Board. No particular weight is given to one factor over another on a general basis, but rather the factors are weighted in relationship to the perceived needs of the Board at the time of selecting nominees. The nominating and corporate governance committee will evaluate candidates recommended by shareowners on the same basis as they evaluate other candidates.

 

Director Compensation. Compensation of non-officer directors of the Company during 2006 included an annual retainer fee of $81,000, of which $2,500 was payable monthly in cash and $51,000 was deposited in the director’s account under the Company’s Deferred Compensation Plan in December 2006 and converted to 1300.357 common stock units based on the closing price of the Company’s Common Stock on November 30, 2006. All non-officer directors received $1,200 for each Board meeting and $1,200 for each committee meeting attended. The lead director and the chairman of the audit committee each received an additional $10,000 cash retainer. The chairmen of the compensation and nominating and corporate governance committees received an additional $5,000 annual cash retainer in 2006. Each chairman of a board committee also received a meeting fee of $1,200 for each meeting (either in person or by phone) with management to address committee matters. These amounts represent the total fees paid to directors in their capacities as directors of the Company and OG&E.

Under the Company’s Deferred Compensation Plan, non-officer directors may defer payment of all or part of their attendance fees and the cash portion of their annual retainer fee, which deferred amounts are credited to their account as of the first day of the month in which the deferred amounts otherwise would have been paid. Amounts credited to the accounts are assumed to be invested in one or more of the investment options permitted under the Company’s Deferred Compensation Plan. During 2006, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company’s Common Stock, a money market fund, a bond fund and several stock funds. When an individual ceases to be a director of the Company, all amounts credited under the Company’s Deferred Compensation Plan are paid in cash in a lump sum or installments.

Historically, for those directors who retired from the Board of Directors after ten years or more of service, the Company and OG&E continued to pay their annual cash retainer until their death. In November 1997, the Board eliminated this retirement policy for directors. Directors who retired prior to November 1997, however, will continue to receive benefits under the former policy.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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Director Compensation

 

 

 

(1)  Amounts in this column represent the dollar value of the annual retainer that was deposited in the director’s account under the Directors’ Deferred Compensation Plan. As of December 31, 2006, the number of common stock units in the Company Common Stock Fund for each of the directors was as follows: Mr. Champlin, 52,690 common stock units; Mr. Corbett, 36,506 common stock units; Mr. Durrett, 22,643 common stock units; Mr. Groendyke, 9,564 common stock units; Mr. Kelley, 33,384 common stock units; Ms. Lambert, 5,067 common stock units; Mr. Lorenz, 4,804 common stock units; Mr. White, 40,442 common stock units; and Mr. Williams, 10,555 common stock units.

 

(2)  Mr. Durrett retired from the Board in May 2006.

 

 

 

 

 

 

 

 

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PROPOSAL NO. 2

RATIFICATION OF THE APPOINTMENT OF ERNST & YOUNG LLP AS THE COMPANY’S

PRINCIPAL INDEPENDENT ACCOUNTANTS FOR 2007

 

The Audit Committee of the Board of Directors has selected Ernst & Young LLP as principal independent accountants to audit the accounts of the Company for the fiscal year ending December 31, 2007. Ernst & Young LLP was originally selected by the Board, upon the recommendation of the Audit Committee, as principal independent accountants for the Company effective May 16, 2002.

While the Audit Committee is responsible for the appointment, retention, termination and oversight of the Company’s principal independent accountants, the Audit Committee and the Board are requesting, as a matter of policy, that shareowners ratify the appointment of Ernst & Young LLP as the Company’s principal independent accountants. The Audit Committee is not required to take any action as a result of the outcome of the vote on this proposal. However, if the shareowners do not ratify appointment, the Audit Committee may investigate the reasons for the shareowners’ rejection and may consider whether to retain Ernst & Young LLP or to appoint another auditor. Furthermore, even if the appointment is ratified, the Audit Committee in its discretion may direct the appointment of different principal independent accountants at any time during the year if it determines that such a change would be in the best interests of the Company and its shareowners.

Representatives of Ernst & Young LLP will be present at the Annual Meeting and will have an opportunity to make a statement if they so desire. Such representatives will be available to respond to appropriate questions from the shareowners at the Annual Meeting.

The affirmative vote of the holders of a majority of the votes of shares of Common Stock present in person or by proxy and entitled to vote at the Annual Meeting will be required for the ratification of the appointment of Ernst & Young LLP as the Company’s principal independent accountants for 2007. Abstentions from voting in this matter are treated as votes “AGAINST.”

The Board of Directors recommends a vote “FOR” the ratification of the appointment of the Company’s principal independent accountants. Proxies solicited by the Board of Directors will be voted “FOR” the ratification of the appointment of the Company’s principal independent accountants, unless a different vote is specified.

 

 

 

 

 

 

 

 

 

 

 

 

 

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REPORT OF AUDIT COMMITTEE

 

The audit committee of the Board of Directors of the Company (the “Audit Committee”) oversees the Company’s financial reporting process on behalf of the Board of Directors. Management, however, has the primary responsibility for the financial statements and the reporting process including the systems of internal controls.

 

The Audit Committee has five members, none of whom has any relationship to the Company that interferes with the exercise of his or her independence from management and the Company, and each of whom qualifies as independent under the standards used by the New York Stock Exchange, where the Company’s shares are listed. The Audit Committee operates under a written charter that has been approved by the Board of Directors. The Audit Committee annually reviews and reassesses the adequacy of its charter. Among other things, the charter specifies the policies for selecting the auditors (including rotation for the audit partner) and the scope of the Audit Committee’s responsibilities and how it carries out those responsibilities, including structure, processes and membership requirements.

 

In fulfilling its oversight responsibilities regarding the 2006 financial statements, the Audit Committee reviewed with Company management the audited financial statements contained in our Annual Report. The Audit Committee’s review included a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements.

 

The Audit Committee also reviewed with the Company’s independent auditors the Company’s 2006 financial statements and management’s assessment of the Company’s internal control over financial reporting. The Company’s independent auditors are responsible for expressing an opinion on the conformity of our audited financial statements with accounting principles generally accepted in the United States and on management’s assessment of the Company’s internal control over financial reporting. Our review with the independent auditors included a discussion of the auditors’ judgments as to the quality, not just the acceptability, of the Company’s accounting principles and such other matters as are required to be discussed with the Audit Committee under Statement on Auditing Standards No. 61, as amended. In addition, the Audit Committee discussed with the independent auditors the auditors’ independence from management and the Company, including the matters in the written disclosures received by the Audit Committee pursuant to Rule 3600T of the Public Company Accounting Oversight Board.

 

The Audit Committee also discussed with the Company’s internal and independent auditors the overall scope and plans for their respective audits for 2007. The Audit Committee meets with the internal and independent auditors, with and without management present, to discuss the results of their examinations, their evaluations of the Company’s internal controls, and the overall quality of the Company’s financial reporting. The Audit Committee held four meetings during 2006 and the Chairman of the Audit Committee conducted six conferences with management by telephone or in person, to discuss Audit Committee matters.

 

Fees for Independent Auditors

 

Audit Fees

 

Total audit fees for 2006 were $1,996,069 for the Company’s 2006 financial statement audit. These fees include $682,669 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $15,750 for services in support of debt and stock offerings. Total audit fees for 2005 were $2,107,307 for the Company’s 2005 financial statement audit. These fees include $775,500 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $37,321 for services in support of debt and stock offerings.

 

The aggregate audit fees include fees billed for the audit of the Company’s annual financial statements and for the reviews of the financial statements included in the Company’s Quarterly Reports on Form 10-Q. For 2006, this amount includes estimated billings for the completion of the 2006 audit, which were rendered after year-end.

 

Audit-Related Fees

 

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2006 were $89,575, of which $73,575 was for employee benefit plan audits and $16,000 for other audit-related services.

 

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2005 were $82,500, of which $67,500 was for employee benefit plan audits and $15,000 for other audit-related services.

 

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Tax Fees

 

The aggregate fees billed for tax services for the fiscal year ended December 31, 2006 were $331,499. These fees include $239,555 for tax preparation and compliance ($74,000 for the review of federal and state tax returns and $165,555 for assistance with examinations and other return issues) and $91,944 for other tax services.

 

The aggregate fees billed for tax services for the fiscal year ended December 31, 2005 were $292,096. These fees include $198,758 for tax preparation and compliance ($76,732 for the review of federal and state tax returns and $122,026 for assistance with examinations and other return issues) and $93,338 for other tax services.

 

All Other Fees

 

There were no other fees billed to the Company in 2006 or 2005 for other services.

 

The Audit Committee has considered whether the provision of non-audit services by the Company’s principal independent public accountants is compatible with maintaining auditor independence.

 

In reliance on the review and discussions referred to above, the Audit Committee recommended to the Board of Directors, and the Board has approved, that the Company’s audited financial statements be included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2006, for filing with the SEC. The Audit Committee selected Ernst & Young LLP as the Company’s independent public accountants for 2007.

 

Audit Committee Pre-Approval Procedures

 

Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. Our Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services, are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the independent public accountants for additional services not contemplated in the original pre-approval. In those instances, we will obtain the specific pre-approval of the Audit Committee before engaging the independent public accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee’s responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

 

For 2006, 100% of the audit-related fees, tax fees and all other fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.

 

Audit Committee

Robert Kelley, Chairman

Herbert H. Champlin, member

Luke R. Corbett, member

Linda Petree Lambert, member

Robert O. Lorenz, member

 

 

 

 

 

 

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EXECUTIVE OFFICERS’ COMPENSATION

 

The following discussion and analysis is intended to present the material principles underlying our executive compensation policies and decisions and the key factors relevant to an analysis of those policies and decisions.

 

COMPENSATION DISCUSSION AND ANALYSIS

 

General. The Compensation Committee of the Board of Directors of the Company (the “Committee”) administers our executive compensation program. Our executive compensation program is premised on two basic principles. First, our overall compensation levels must be sufficiently competitive to attract and retain talented leaders. At the same time, we believe that compensation should be set at reasonable and responsible levels, consistent with our continuing focus on controlling costs. Second, our executive compensation program should be substantially performance-based and should align the interests of our executives with those of our shareowners.

 

Three key components of our executive compensation program are salary, annual incentive awards under our Annual Incentive Compensation Plan and long-term incentive awards under our Stock Incentive Plan. Both the Annual Incentive Compensation Plan and Stock Incentive Plan were approved by our shareowners at the 2003 Annual Shareowners’ Meeting. Salaries are a critical element of executive compensation because they provide executives with a base level of monthly income. The Committee’s intent in setting salaries is to pay competitive rates based on an individual’s experience and level of performance. The annual and long-term incentive awards of an executive’s compensation are directly linked to performance. Payouts of these portions of an executive’s compensation are placed at risk and require the accomplishment of specific results that are designed to benefit our shareowners and the Company, both in the long and short term. Specifically, awards under the Annual Incentive Plan provide officers and key employees an opportunity to earn an annual cash bonus for achieving specified Company performance-based goals established for the year. These Company performance goals typically are tied to measures of operating performance. Awards under the Stock Incentive Plan are equity-based and require the achievement over a three-year period of specific Company performance goals that are tied directly to the performance of the Company’s stock or to factors that affect the performance of the Company’s stock.

 

Our executive compensation program recognizes that our senior executives are in a position to influence directly the Company’s achievement of targeted results and strategic initiatives. For this reason, as an individual’s position and responsibilities increase, a greater portion of the officer’s compensation is at risk and consists of performance-based pay dependent on the achievement of performance objectives. This is shown by the level of salaries, annual incentive awards and long-term incentive awards set for our five most highly paid executive officers in 2006. For each of these executive officers, salary represented less than 60% of the potential amount that could be received through achievement, at target level, of the Company performance goals set in connection with the officer’s annual and long-term incentive awards. As a result, our executive compensation program is designed to reward executives with a highly-competitive level of compensation during years of excellent Company performance and, conversely, in years of below-average performance, their compensation may be below competitive levels.

 

In an effort to measure the continued reasonableness and competitiveness of our executive compensation policies, the Committee in 2005 followed its past practice and engaged Towers Perrin, a nationally recognized compensation consulting firm, to help survey the marketplace. In setting base salaries and making annual and long-term incentive awards for 2006, the Committee considered the salaries and annual and long-term incentive awards for executives with similar duties at the 50th percentile within the following three groups: (i) Towers Perrin’s 2005 Energy Services Industry Executive Compensation Database (the “Energy Services Survey Group”), consisting of approximately 94 energy services organizations, many of which have significant utility operations, (ii) Towers Perrin’s 2005 General Industry Executive Compensation Database (the “General Industry Survey Group”), consisting of more than 800 companies in general industries and (iii) the average of the Energy Services Survey Group and the General Industry Survey Group (the “Blended Industry Survey Group”).  All compensation data from these surveys was size-adjusted so that it would compare to the Company’s or a subsidiary’s projected 2006 revenues, as appropriate, and was updated using a 3.60 percent update factor to reflect anticipated 2006 compensation levels. Compensation to be paid at the 50th percentile to an executive in the General Industry Survey Group is typically higher, often significantly higher, than the compensation that would be paid to an executive with similar duties in the Energy Services Survey Group. This difference is largely attributable to higher compensation being paid in general industry as compared to the utility industry, which, as noted above, comprises a significant portion of the Energy Services Survey Group.

 

 

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While the three survey groups are reviewed by our senior management in making recommendations to the Committee and by the Committee in making compensation decisions, both management and the Committee have utilized, where appropriate, the Blended Industry Survey Group for base salary, target annual incentive awards and target long-term incentive awards. The rationale for utilizing the blended industry data has been to:

 

 

 

 

In practice, however, most utility-specific jobs (e.g., Vice President of Transmission) have no comparable jobs in general industry and can only be benchmarked to the utility industry. As a result, the Company has targeted the 50th percentile market pay data of the Blended Industry Survey Group for executives whose responsibilities are not limited to utility operations and the 50th percentile market pay data of the Energy Services Survey Group for executives whose responsibilities are limited to utility operations. This market pay data for an executive is intended to represent what would be paid to a hypothetical, seasoned performer in a job having similar responsibilities and scope, in an organization of similar size and type, to the executive in question. However, actual compensation recommendations by senior management and decisions on compensation by the Committee can vary from this market data for numerous reasons, including an individual’s performance, experience level and internal equity.

 

An individual’s performance is judged through an annual performance evaluation, which involves, for each member of senior management (other than the CEO), an objective scoring by such individual’s supervisor of various competencies, including the individual’s management skills, business knowledge and achievement of various performance and development objectives set at the beginning of the year. The annual performance evaluations are reviewed with the Committee and are used by the CEO and COO in making compensation recommendations to the Committee. The Committee also conducted an annual performance evaluation of the CEO.

 

The Committee met in December 2005 and set each executive officer’s 2006 salary and, subject to potential adjustment at its meeting in February 2006, each executive officer’s target annual incentive award and target long-term incentive award for 2006 based primarily on the individual’s annual performance evaluation and on the comparable amounts shown at the 50th percentile for an executive officer with similar duties in the Blended Industry Group or, in the case of an executive officer whose responsibilities are limited to utility operations, in the Energy Services Survey Group. The target annual and long-term incentive awards were expressed as percentages of salary. While the setting of the target annual incentive and long-term incentive awards is an important part of the executive compensation process, another critical part is the setting of the Company performance goals for such awards. This is a critical part because the level of achievement of the Company performance goals will determine the amount, if any, of the possible payouts of the target annual and long-term incentive awards.

 

Following a discussion of recommendations by the CEO and COO, the Committee, at its meeting in February 2006, set the Company performance goals for annual incentive and long-term incentive awards. These Company performance goals for executive officers are described in detail below and were intended to align the executive’s interests with our shareowners by having achievement of Company performance goals be directly beneficial to our shareowners. The Committee also approved the form of the long-term compensation awards, which, like recent prior years, were equity-based and consisted entirely of performance units. The Committee chose to take these actions at its meeting in February 2006 because the Committee wanted to know the Company’s audited 2005 financial results before setting many of the 2006 performance goals and such audited financial results were not available until shortly before the meeting.

 

In setting the executive compensation for any given year, the Committee historically (including 2006) has not looked to compensation earned by executives in prior years, including specifically amounts realized from grants in prior years of annual incentive awards or long-term incentive awards. The primary reasons are that our executive compensation program seeks to have all components of executive compensation be competitive, and the portions of an executive’s compensation that could vary materially from year to year are primarily performance-based. As a result, high levels of executive compensation in a particular year historically have resulted from excellent Company performance, which the Committee believed did not warrant a reduction in future compensation levels or in our compensation principles. There also is no established policy or target for the allocation between either cash and non-cash or annual and long-term compensation. Rather, the Committee reviews information from Towers Perrin to determine the appropriate level and mix of incentive compensation.

 

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As indicated above, our senior management and, in particular our CEO and COO, played an important part in setting 2006 executive compensation. Besides developing recommendations for the Company performance goals that needed to be met for payouts of 2006 annual incentive awards and long-term incentive awards, they reviewed with the Committee at its November 2005 meeting the performance evaluations of each member of management (other than the CEO), with the CEO giving his performance evaluation of the COO. They also reviewed and discussed with the Committee at its November meeting their recommendations for each member of management (other than the CEO) of 2006 salaries, target annual incentive awards and target long-term incentive awards. As noted above, the CEO’s performance evaluation and the setting of his potential salary, target annual incentive award and target long-term incentive award were conducted by the Committee without any members of management present. The Committee’s performance evaluation of the CEO, along with his 2006 salary, target annual incentive award and target long-term incentive award, were reviewed by the Committee with all independent members of the Board.

 

The following three sections illustrate the application of our executive compensation principles and discuss in detail the salaries, bonuses and long-term compensation that were approved by the Committee and were paid in connection with 2006 compensation.

 

Base Salary. As explained above, the base salaries for our executive officers in 2006 were designed to be competitive with the Blended Industry Survey Group for most of our executive officers and with the Energy Services Survey Group for those officers whose responsibilities are limited to utility operations. Base salaries of our executive officers were determined based primarily on an individual’s annual performance evaluation and the salaries at the 50th percentile of the range for executives with similar duties in the appropriate survey group. The salaries of executive officers for 2006 were initially determined in December 2005, with an effective date of January 1, 2006. The 2006 base salary amounts for the most highly compensated executive officers are shown in the salary column of the Summary Compensation Table on page 23. The percentage increase (decrease) in salaries for these individuals was as follows: Steven Moore, 4%; Peter Delaney, 7%; James Hatfield, 6%; Dan Harris, 9%; and Steven Gerdes, (5%).

 

Annual Incentive Compensation. Annual incentive awards with respect to 2006 performance were made under the Annual Incentive Compensation Plan to 90 employees, including all executive officers. The Plan provides key management personnel with annual incentive awards, the payment of which is dependent entirely on the achievement of the Company performance goals that, for 2006, were established by the Committee in February 2006.

 

The amount of the award for each executive officer was expressed as a percentage of base salary (the “targeted amount”), with the officer having the ability, depending upon achievement of the Company performance goals, to receive from 0% to 150% of such targeted amount. For 2006, the targeted amounts ranged from 30% to 85% of base salary for executive officers and were at or slightly below the 50th percentile of the level of such awards granted to comparable executives in the Blended Industry Survey Group or, in the case of executive officers whose responsibilities are limited to utility operations, to comparable executives in the Energy Services Survey Group. For the most highly compensated executives reported in the Summary Compensation Table on page 23, the targeted amounts were as follows: Mr. Moore, 85% of his 2006 salary; Mr. Delaney, 70% of his 2006 salary; Mr. Hatfield, 55% of his 2006 salary; Mr. Harris, 40% of his 2006 salary; and Mr. Gerdes, 30% of his 2006 salary.

 

As noted above, potential payouts of targeted amounts are dependent entirely on achievement of Company performance goals. For Messrs. Moore and Delaney, the two most senior executive officers of the Company, the Company performance goals were based: (i) 50% on a Company consolidated earnings per share target established by the Committee (the “Earnings Target”), (ii) 25% on a combined operating and maintenance expense and capital expenditure target for the Company and OG&E established by the Committee (the “O&M/Capital Target”), and (iii) 25% on a consolidated net income target of Enogex and its subsidiaries (the “Unregulated Income Target”) established by the Committee. At least two of these three Company performance goals were used in establishing the corporate goals for all other executive officers. However, the weighting of the Company performance goals was slightly different for the remaining executive officers based on their responsibilities. For two executive officers whose responsibilities pertain primarily or exclusively to utility operations, the Company performance goals were based 50% on the Earnings Target and 50% on the O&M/Capital Target, and for Mr. Harris, whose responsibilities are focused on Enogex, his Company performance goals were based 40% on the Earnings Target, 40% on the Unregulated Income Target and 20% on a return on invested capital target for Enogex (the “ROIC Target”) established by the Committee. For the remaining executive officers, the Company performance goals were based 50% on the Earnings Target, 30% on the O&M/Capital Target and 20% on the Unregulated Income Target.

 

 

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For each Company performance goal, the Committee established a minimum level of performance (below which no payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made). The following table shows the target levels of performance for the four Company performance goals set for executive officers in 2006, the actual level of performance, as calculated pursuant to the terms of the awards, and the percentage payout of the targeted amount based on the actual level of performance:

 

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(1) As indicated above, calculation of the Earnings Target, O&M/Capital Target and Unregulated Income Target are derived from the Company’s financial statements, with the Earnings Target being the Company’s reported consolidated diluted earnings per share from continuing operations, the Unregulated Income Target being the reported consolidated net income of Enogex from continuing operations, the O&M/Capital Target being the operating and maintenance expenditures and capital expenditures of various OGE Energy and OG&E business units and ROIC being generally the sum of consolidated net operating profit less adjusted taxes of Enogex divided by the amount of Enogex’s average invested capital. Notwithstanding the foregoing, the Committee at the time of setting these Company performance goals specifically excluded various items in calculating the achievement of these performance goals, including, for example, increases or decreases in revenues, expenses, gains or losses from any change in accounting principles occurring during 2006 and any gains or losses from the sale, other disposition or impairment of any business or asset during 2006. While the overall effect of these exclusions was to lower Enogex’s consolidated net income from continuing operations from the $77.5 million reported in Enogex’s financial statements to $76.2 million, the exclusions had no effect on the payouts to executive officers of the Earnings Target, O&M/Capital Target, Unregulated Income Target or the ROIC Target.

 

The percentage of the targeted amount that an executive officer ultimately received based on corporate performance was subject to being decreased, but not increased, at the discretion of the Committee. For 2006, corporate performance of the Earnings Target, the ROIC Target, the O&M/Capital Target and the Unregulated Income Target exceeded the minimum levels of achievement established by the Committee and, based on the level of achievement, the Committee approved payouts under the Annual Incentive Compensation Plan to executive officers ranging from approximately 35% to 117% of their base salaries and from approximately 116% to 150% of their targeted amounts. Payouts under the Annual Incentive Compensation Plan are in cash and the amounts paid to the Company’s most highly compensated executive officers are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 23.

 

Long-Term Incentive Compensation. Long-term incentive awards also were made in 2006 under our Company’s Stock Incentive Plan. The Plan provides for the grant of any or all of the following types of awards: stock options, stock appreciation rights, restricted stock and performance units. In 2006, the Committee set a targeted amount of long-term incentive compensation to be awarded each executive officer, which amount was expressed as a percentage of the individual’s base salary as of January 1, 2006. For 2006, the targeted amount ranged from 30% to 150% of base salary for executive officers and was at or below the 50th percentile of the level of such awards granted to comparable executives in the Blended Industry Survey Group or, in the case of executive officers whose responsibilities are limited to utility operations, to comparable executives in the Energy Services Survey Group. The targeted amount (expressed as a percentage of salary) of long-term incentive compensation for several executive officers of the Company was set by the Committee more than 10% below the level of such awards granted to comparable executives in the appropriate survey group. This action by the Committee was due to long-term compensation for comparable executives in the appropriate survey group being substantially higher than the amounts awarded by the Committee in the past to such executives of the Company and the Committee’s

 

 

 

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desire to make up such shortfall over a period of several years rather than through a substantial increase in a particular year. For the most highly compensated executives reported in the Summary Compensation Table on page 23, the targeted amounts of long-term incentive compensation were as follows: Mr. Moore, 150% of his 2006 salary; Mr. Delaney, 120% of his 2006 salary; Mr. Hatfield, 85% of his 2006 salary; Mr. Harris, 55% of his 2006 salary; and Mr. Gerdes, 35% of his 2006 salary.

 

Historically, the Committee had awarded long-term compensation in the forms of stock options and restricted stock. At its meeting in the fourth quarter of 2002, the Committee chose to discontinue awarding restricted stock and, instead, to make awards of stock options and performance units commencing in 2003, with 50% of an executive officer’s award being in the form of stock options and 50% in the form of performance units. For 2004, the Committee chose to place less emphasis on stock options with 25% of an executive officer’s award of long-term compensation being in the form of stock options and 75% in the form of performance units. In 2005, the Committee decided to cease awarding stock options and instead, for both 2005 and 2006, awarded all long-term compensation in the form of performance units, with, as explained below, payout of the performance units being dependent on achievement of Company performance goals set by the Committee. Specifically, for 75% of the performance units awarded in 2006, the Company performance goal is based on the relative total shareholder return (“TSR”) of the Company’s Common Stock over the three-year period ending December 31, 2008 compared to a peer group and, for the remaining 25%, the Company performance goal is based on the growth in the Company’s earnings per share over the same three-year period compared to an earnings growth target (the “Earnings Growth Target”) set by the Committee.

 

The performance units were granted to executive officers on February 22, 2006, immediately following the Committee’s meeting on such date. The number of performance units granted was determined by taking the amount of the executive’s long-term compensation to be delivered in performance units (expressed as a percentage of the executive’s 2006 base salary and as determined above) and dividing that amount by $19.734, which was the value of a performance unit computed in a manner consistent with SFAS No. 123(R) based on a recent closing price of the Company’s Common Stock of $26.50 per share. This resulted in executives receiving a number of performance units with an expected value at the date of grant from 0% to 150% of their 2006 base salaries. All payouts of such performance units will be made in shares of the Company’s Common Stock, which causes the value of the performance units to be substantially dependent upon the changing value of the Company’s Common Stock in the marketplace. As indicated above, the terms of 75% of the performance units granted to each executive officer in 2006 entitle the officer to receive from 0% to 200% of the performance units granted depending upon the Company’s TSR over a three-year period (defined as share price increase (decrease) since December 31, 2005 plus dividends paid, divided by share price at December 31, 2005) measured against the TSR for such period of a peer group selected by the Committee. The peer group for measuring the Company’s TSR performance consists of approximately 80 utility holding companies and gas and electric utilities in the Standard & Poor’s Utility Index. At the end of the three-year period (i.e., December 31, 2008), the terms of these performance units provide for payout of 100% of the performance units initially granted if the Company’s TSR is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if the Company’s TSR is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Company’s TSR is below the 50th percentile of the peer group, with no payout for performance below the 35th percentile.

 

For the remaining 25% of performance units granted to each executive officer in 2006, the officer is entitled to receive from 0% to 200% of the performance units granted depending upon the growth in the Company’s earnings per share over the three-year period ending December 31, 2008. The growth in the earnings per share will be measured from $1.83 per share (which consisted of the $1.77 earned in 2005 from continuing operations plus $0.06 per share for a one time event in 2005 that lowered earnings from continuing operations by $0.06 per share) against the Earnings Growth Target (4% per year) set by the Committee for such period. At the end of the three-year period (i.e., December 31, 2008), the terms of these performance units provide for payout of 100% of the performance units initially granted if the rate of growth of the Company’s earnings per share during such period is at the Earnings Growth Target, with higher payouts for growth rates in excess of the Earnings Growth Target up to 200% for growth rates at or above 150% of the Earnings Growth Target and payout of less than 100% for growth rates below the Earnings Growth Target, with no payouts for growth rates below 62.5% of the Earnings Growth Target. The Company’s earnings growth rate is calculated on a point-to-point basis by dividing by one-third the percentage increase in the Company’s earnings per share for the year ended December 31, 2008, compared to the benchmark of $1.83 for 2005.

 

 

 

 

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In January 2004, as part of their long-term compensation executive officers received performance units whose payout was dependent on the achievement of a Company performance goal based on TSR for the three-year period ended December 31, 2006. The Company’s TSR for such period was at the 77.70th percentile (approximately the top 23%) of the peer group. Stated differently, the percentage return on the Company’s Common Stock, consisting of increases (decreases) in the price of the Company’s Common Stock plus dividends paid, was higher than 77.70% of the companies in the Standard & Poor’s Utility Index during the period commencing on January 1, 2004 and ending on December 31, 2006. This high level of performance resulted in payouts in February 2007 of 169.25% of the performance units originally awarded in January 2004. The value of these payouts is reflected in the Stock Awards – Value Realized on Vesting column of the Option Exercises and Stock Vested Table on page 26.

 

CEO Compensation. The 2006 compensation for Mr. Moore consisted of the same components as the compensation for other executive officers. Mr. Moore’s 2006 salary was increased from $750,000 to $780,000, and his 2006 targeted award under the Annual Incentive Plan, was increased from 80% to 85% of his base salary, which the Committee believed were appropriate levels based on his performance and the amounts paid to a chief executive officer in the Blended Industry Survey Group. As a result of 2006 corporate performance of the corporate goals described above, he received a payout of $913,183 under the Annual Incentive Plan, representing approximately 117% of his base salary and 137.74% of his targeted award. Mr. Moore also received as long-term compensation in February 2006 an award of 59,288 performance units, having an estimated value of 150% of his 2006 base salary. The terms of these performance units are identical to those awarded other executives and are described above. The award of performance units in 2006 made to Mr. Moore was based on his prior performance and a comparison of his award to the long-term compensation of other chief executive officers in the 50th percentile of the Energy Services Survey Group and of the Blended Industry Survey Group. Consideration also was given by the Committee to Mr. Moore’s prior experience with the Company and OG&E, his demonstrated leadership skills and his positive reputation within the community and utility industry.

 

Like other executive officers, Mr. Moore also received in February 2007 a payout of 169.25% of the performance units granted to Mr. Moore in January 2004 based on the Company’s TSR for the three years ended December 31, 2006 being at the 77.70th percentile (approximately the top 23%) of the peer group selected by the Committee. This resulted in Mr. Moore receiving a payout of 61,566 units, of which two-thirds (41,044) were paid in shares of the Company’s Common Stock and one-third (20,522) was paid in cash based on the high and low prices of the Company’s Common Stock on the date the Committee approved the payout. The value of this payout, based on the closing price of the Company’s Common Stock on December 31, 2006, is reported in the Stock Awards – Value Realized on Vesting column of the Option Exercises and Stock Vested Table on page 26.

 

Other Benefits. As noted above, the key components of our executive compensation program are salary, annual incentive awards and long-term incentive awards. Virtually all of our employees, including executive officers, are eligible to participate in our pension plan and supplemental restoration plan that enables participants, including executive officers, to receive the same benefits that they would have received under our pension plan in the absence of limitations imposed by the federal tax laws. In addition, a Supplemental Executive Retirement Plan (the “SERP”), which was adopted in 1993, offers supplemental pension benefits to specified lateral hires. Mr. Delaney is the only executive officer who participates in the SERP. Mr. Delaney’s participation in the SERP was the result of arms-length bargaining between Mr. Delaney and the Company at the time of his hire in April 2002 as Executive Vice President of the Company. For additional information on the pension plan, restoration plan and SERP, see “Pension Benefits” below.

 

Almost all employees of the Company, including the executive officers, also are eligible to participate in our tax-qualified defined contribution savings plan (the “Retirement Savings Plan”). Under the Retirement Savings Plan, participants may contribute between two percent and 19 percent of their compensation. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; or (ii) a contribution made on an after-tax basis. The Company will match, depending upon the participant’s years of service and date of initial participation, 50 percent, 75 percent or 100 percent of the first six percent of compensation. Participants’ contributions are fully vested and non-forfeitable. The Company match contributions vest over a six-year period. After two years of service, participants become 20 percent vested in their Company contribution account and vest an additional 20 percent for each subsequent year of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Company’s pension plan, in the event of their termination due to death, permanent disability or upon attainment of age 65 while employed by the Company or its affiliates.

 

 

 

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The Company also maintains a non-qualified deferred compensation plan that is described below under “Nonqualified Deferred Compensation.”

 

The Company also offers executive officers a limited amount of perquisites. These include up to $7,500 annually for tax and financial planning services, payment of dues at luncheon and country clubs, reimbursement for liability insurance, an annual physical exam and, in the case of Mr. Moore, a leased car. The value of the perquisites received by each executive officer, other than Mr. Moore, was less than $10,000 in 2006. In reviewing the perquisites and benefits under the SERP, Retirement Savings Plan, deferred compensation plan, pension plan and related restoration plan, the Committee sought in 2006 to provide participants with benefits at least commensurate with those offered by other utilities of comparable size.

 

Change-of-Control Provisions. Each of the executive officers has an employment agreement that provides for specified benefits upon termination following a change of control. These employment agreements are described in detail below under the heading “Potential Payments Upon Termination or Change of Control.” In addition, pursuant to the terms of the Company’s incentive compensation plans, upon a change of control, all stock options will vest immediately and, for a 60-day period following the change of control, executive officers may surrender their options and receive in return a cash payment equal to the excess of the change of control price (as defined) over the exercise price; all performance units will vest and be paid out immediately in cash as if the applicable performance goals had been satisfied at target levels; and any annual incentive award outstanding at the participant’s termination for any reason other than cause within 24 months after the change of control will be paid in cash at target level on a prorated basis.

 

Stock Ownership Guidelines. In an effort to further align management’s interests with those of the share-owners, the Committee recommended, and the Board of Directors adopted, stock ownership guidelines for the officers of the Company and its subsidiaries during 2004. The Committee believes that linking a significant portion of an officer’s current and potential future net worth to the Company’s success, as reflected in the ownership of the Company’s Common Stock and the price of the Company’s Common Stock, helps to ensure that officers have a stake similar to that of the Company’s shareowners. The share ownership guideline for each executive is based on the executive’s position. The guideline for Chairman of the Board and CEO is five times base salary. The guidelines for other Company officers range from three and one-half to one and one-half times their base salaries. Each executive is expected to achieve the applicable ownership guideline within five years. Similar guidelines were adopted for members of the Board of Directors at a level of five times their annual retainer.

 

Financial Restatement. It is the Board of Directors’ policy that the Compensation Committee will, to the extent permitted by governing law, have the sole and absolute authority to make retroactive adjustment to any cash or equity-based incentive compensation paid to executive officers and certain other officers where the payment was predicated upon the achievement of certain financial results that were subsequently the subject of a restatement. Where applicable, the Company will seek to recover any amount determined to have been inappropriately received by the individual executive.

 

Tax and Accounting Issues.

 

Deductibility of Executive Compensation. A Federal tax law currently limits our ability to deduct an executive’s compensation in excess of $1,000,000 unless such compensation qualifies as “performance based compensation” or certain other exceptions are met. The Committee has continued to analyze the structure of its salary and various compensation programs in light of this law. The Committee’s present intent is to take appropriate steps to ensure the continued deductibility of its executive compensation. For this reason, the Committee and the Board of Directors recommended, and the shareowners approved, the Stock Incentive Plan and the Annual Incentive Plan at the 2003 Annual Meeting so that certain compensation payable thereunder would qualify for the “performance based compensation” exception to the $1,000,000 deduction limit and thereby continue to be deductible by the Company.

 

Nonqualified Deferred Compensation. On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law, changing the tax rules applicable to nonqualified deferred compensation arrangements. While the final regulations have not become effective yet, the Company believes it is operating in good faith compliance with the statutory provisions which were effective January 1, 2005. A more detailed discussion of the Company’s nonqualified deferred compensation arrangements is provided below under the heading “Nonqualified Deferred Compensation.”

 

Accounting for Stock-Based Compensation. Beginning on January 1, 2006, the Company began accounting for stock-based payments, including its stock options and performance units, in accordance with the requirements of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”

 

 

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SUMMARY COMPENSATION TABLE

 

The following table provides information regarding compensation paid or to be paid by us or any of our subsidiaries to the Chief Executive Officer, the Chief Financial Officer and the three other most highly compensated executive officers for 2006.

 

 

 

 

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Grants of Plan-Based Awards Table

 

 

Amounts in columns (c), (d) and (e) of the Grants of Plan-Based Awards table above represent the minimum, target and maximum amounts that would be payable pursuant to the 2006 annual incentive awards made under the Annual Incentive Compensation Plan. As described in the Compensation Discussion and Analysis section above, the amount that each executive officer received was dependent upon performance against two or more of the following performance measures: Earnings Target, O&M/Capital Target, Unregulated Income Target and ROIC Target. For each Company performance measure, the Compensation Committee established a minimum level of performance (below which no payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made). The percentage of the targeted amount that an executive officer ultimately received based on corporate performance was subject to being decreased, but not increased, at the discretion of the Committee. For 2006, payouts of these annual incentive awards were made in cash and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

 

Amounts in columns (f), (g) and (h) above represent awards of performance units under the Company’s Stock Incentive Plan. All payouts of such performance units will be made in shares of the Company’s Common Stock. As described in more detail in the Compensation Discussion and Analysis section above, the terms of 75% of the performance units granted to each executive officer in 2006 entitle the officer to receive from 0% to 200% of the performance units granted depending upon the Company’s TSR over a three-year period measured against the TSR for such period by a peer group selected by the Committee. At the end of the three-year period (i.e., December 31, 2008), the terms of these performance units provide for payout of 100% of the performance units initially granted if the Company’s TSR is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if the Company’s TSR is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Company’s TSR is below the 50th percentile of the peer group, with no payout for performance below the 35th percentile.

 

For the remaining 25% of performance units granted in 2006, the officer is entitled to receive from 0% to 200% of the performance units granted based on the growth in the Company’s earnings per share measured against the Earnings Growth Target set by the Committee for such period. At the end of the three-year period (i.e., December 31, 2008), the terms of these performance units provide for payout of 100% of the performance units initially granted if the rate of growth of the Company’s earnings per share during such period is at the Earnings Growth Target, with higher payouts for growth rates in excess of the Earnings Growth Target up to 200% for growth rates at or above 150% of the Earnings Growth Target and payout of less than 100% for growth rates below the Earnings Growth

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Target, with no payouts for growth rates below 62.5% of the Earnings Growth Target. The Company’s earnings growth rate is calculated on a point-to-point basis by dividing by one-third the percentage increase in the Company’s earnings per share for the year ended December 31, 2008, compared to the benchmark of $1.83 for 2005.

 

Based on the fair value of equity awards granted to the named executive officers in 2006 and the base salary of the named executive officers, “Salary” accounted for approximately 30% to 60% of total compensation, while incentive compensation accounted for approximately 40% to 70% of the total compensation, assuming achievement of a target level of performance for each named executive officer. Because the value of certain equity awards included in the Summary Compensation Table is based on the FAS 123R value rather than fair value, these percentages may not be able to be derived using the amounts reflected in the Summary Compensation Table.

 

 

Outstanding Equity Awards at Fiscal Year-End Table

 

 

 

 

 

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Option Exercises and Stock Vested Table

 

 

   

 

 

Pension Benefits Table

 

 

   

 

 

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The Company and OG&E maintain a qualified non-contributory pension plan (the “Retirement Plan”) generally covering all employees who have completed one year of service. Subject to limitations imposed by the Code, benefits payable under the Retirement Plan to employees hired prior to February 1, 2000 are based upon (i) the average of the five highest consecutive years of cash compensation (which for the executives named in the Summary Compensation Table consists of salary and annual bonus or incentive compensation) during an employee’s last ten years prior to retirement and (ii) length of service. Social Security benefits are deducted in determining benefits payable under the Retirement Plan. Compensation covered by the Retirement Plan includes salaries, annual bonuses or incentive compensation and overtime pay. Benefits are reduced for each year prior to age 62 that an employee retires. For an employee retiring prior to age 62, there is an alternative method of computing the reduction in benefits that is based on years of service and age with an employee whose age and years of service total or exceed 80 at the time of retirement receiving no reduction in the benefits payable under the plan. An employee may elect at the time of retirement to receive, in lieu of an annuity, a lump-sum payment equal to the present value of the annuity. For employees hired after January 31, 2000, however, the Retirement Plan is a cash balance plan, under which the Company annually will contribute to the employee’s account an amount equal to 5% of the employee’s annual compensation plus accrued interest. Employees hired prior to February 1, 2000 receive the greater of the cash balance formula or final average compensation formula described above. Retirement benefits are payable to participants upon normal retirement (at or after age 65) or early retirement (at or after attaining age 55 and completing five or more years of service), to former employees after reaching retirement age (or, if elected, following termination) who have completed five or more years of service before terminating their employment and to participants after reaching retirement age (or, if elected, following termination) upon total and permanent disability. Of the named executive officers, Mr. Moore is eligible for early retirement. As indicated above, the benefits payable under the Retirement Plan are subject to maximum limitations under the Code. Should benefits for a participant at the time of retirement exceed the then permissible limits of the Code, the Retirement Restoration Plan will provide benefits through a lump-sum distribution or in monthly installments for a specified period of years actuarially equivalent to the amounts that would have been, but cannot be, payable to such participant annually under the Retirement Plan because of the Code limits. The Company and OG&E fund the estimated benefits payable under the Retirement Restoration Plan through contributions to a grantor trust for the benefit of those employees who will be entitled to receive payments under the Retirement Restoration Plan.

 

In 1993, OG&E adopted a SERP which is an unfunded supplemental plan that is not subject to the benefits limit imposed by the Code. The plan generally provides for an annual retirement benefit at age 65 equal to 65% of the participant’s average cash compensation during his or her final 36 months of employment, reduced by Social Security benefits, by amounts payable under the Retirement and Restoration Retirement Plans described above and by amounts received under pension plans from other employers. For a participant in the SERP who retires before age 65, the 65% benefit is reduced, with the reduction being 1% per year for ages 62 through 64, an additional 2% per year for ages 60 through 61, an additional 4% per year for ages 58 through 59 and an additional 6% per year for ages 55 through 57, so that a participant retiring at age 55 would receive 32% of his average cash compensation during his final 36 months, reduced by the deductions set forth above. Other than Mr. Delaney, no employee participated in the SERP during 2006.

 

 

 

 

 

 

 

 

 

 

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Nonqualified Deferred Compensation Table

 

 

 

The Company has a nonqualified deferred compensation plan that allows key employees, including all executive officers, to defer compensation above government limitations on 401(k) contributions that apply to the Company’s qualified Retirement Savings Plan and to defer taxation on all earnings on compensation deferred into the plan. Under the terms of the nonqualified deferred compensation plan, participants have the opportunity to elect to defer each year up to 70% of their base salary and up to 100% of their bonus.

 

The Company matches deferrals to make up for any match lost in the Retirement Savings Plan because of deferrals to the deferred compensation plan, and to allow for a match on that portion of the first 6% of total compensation deferred that exceeds the limits allowed in the Retirement Savings Plan. Matching credits vest based on years of service, with full vesting after six years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan.

 

Deferrals, plus any Company match, are credited to a special recordkeeping account in the participant’s name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. For 2006, those investment fund options included an OGE Energy Common Stock fund; 500 Index B (MFC Global Investment); Active Bond (John Hancock Advisers, Inc.); Blue Chip Growth (T. Rowe Price); Capital Appreciation (Jennison Associates LLC); Equity-Income (T. Rowe Price); Growth & Income (Grantham, Mayo, Van Otterloo & Co.); Managed (GMO/DMR); Money Market B (MFC Global Investment); Overseas Equity (Capital Guardian Trust Company); and Small Cap Growth (Wellington Management). For 2006, those investment funds had returns of 49.31 percent; 15.56 percent; 4.54 percent; 9.59 percent; 2.38 percent; 19.05 percent; 12.72 percent; 7.48 percent; 4.70 percent; 19.76 percent and 13.47 percent.

 

Normally, payments under the deferred compensation plan begin within one year after retirement. For these purposes, normal retirement age is 65 and the minimum age to qualify for early retirement is age 55 with at least five years of service. Benefits will be paid, at the election of the participant, either in a lump sum or a stream of annual payments for up to 15 years, or a combination thereof. Participants whose employment terminates before they qualify for retirement benefits will receive their vested account balance in one lump sum following termination. Participants also will be entitled to pre- and post-retirement survivor benefits. If the participant dies while in employment before retirement, his or her beneficiary will receive a payment of the account balance plus a supplemental survivor benefit equal to two times the total amount of base salary and bonuses deferred under the plan. If the

 

 

 

 

 

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participant dies following retirement, his or her beneficiary will continue to receive the remaining vested account balance. Additionally, eligible surviving spouses will be entitled to a lifetime survivor annuity payable annually. The amount of the annuity is based on 50% of the participant’s account balance at retirement, the spouse’s age and actuarial assumptions established by the Company’s benefit committee.

 

At any time prior to retirement, a participant may withdraw all or part of amounts attributable to his or her vested account balance at December 31, 2004, subject to a penalty of 10% of the amount withdrawn. In addition, at the time of the initial deferral election, a participant may elect to receive one or more in-service distributions on specified dates without penalty. Hardship withdrawals, without penalty, of amounts attributable to a participant’s vested account balance as of December 31, 2004 may also be permitted at the discretion of the Company’s benefits committee.

 

 

COMPENSATION COMMITTEE REPORT

 

The Compensation Committee oversees (i) the compensation of the Company’s directors and principal officers, (ii) the Company’s executive compensation policy and (iii) the Company’s benefit programs.

 

The Compensation Committee has six members, none of whom has any relationship to the Company that interferes with the exercise of his or her independence from management and the Company, and each of whom qualifies as independent under the standards used by the New York Stock Exchange, where the Company’s shares are listed.

 

The Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis appearing elsewhere in this proxy statement. Based on the review and discussions referred to above, the Compensation Committee recommended to the Company’s Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Proxy Statement on Schedule 14A.

 

Compensation Committee

Luke R. Corbett, Chairman

Herbert H. Champlin, Member

John D. Groendyke, Member

Robert Kelley, Member

Ronald H. White, M.D., Member

J. D. Williams, Member

 

 

 

 

 

 

 

 

 

 

 

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

 

The Company and OG&E have entered into employment agreements with each officer of the Company and OG&E that will become effective only upon a change of control of the Company. Under the agreements, a change of control generally means (i) any acquisition of 20% or more of the Company’s Common Stock (subject to limited exceptions for acquisitions directly from the Company, acquisitions by the Company or one of the Company’s employee benefit plans, or acquisitions pursuant to specified business combinations approved by a majority of the incumbent directors), (ii) directors of the Company as of the date of the agreements and those directors who have been elected subsequently and whose nomination was approved by such directors fail to constitute a majority of the Board, (iii) a merger, share exchange or sale of all or substantially all of the assets of the Company (each, a “business combination”) (except specified business combinations approved by a majority of the incumbent directors), or (iv) shareowner approval of a complete liquidation or dissolution of the Company.

 

Under the agreements, the officer is to remain an employee for a three-year period following a change of control of the Company (the “Employment Period”). During the Employment Period, the officer is entitled to (i) an annual base salary in an amount at least equal to his or her base salary prior to the change of control, (ii) an annual bonus in an amount at least equal to his or her highest bonus in the three years prior to the change of control and (iii) continued participation in the incentive, savings, retirement and welfare benefit plans. The officer also is entitled to payment of expenses and provision of fringe benefits to the extent paid or provided to (i) such officer prior to the change of control or (ii) if more favorable, other peer executives of the Company. In addition, upon a change of control, Mr. Delaney will be considered vested under the SERP if he has not already attained age 55.

 

If, during the Employment Period, the employer terminates the officer’s employment for reasons other than cause or disability or if the officer terminates his or her employment for good reason, the officer is entitled to the following payments: (i) all accrued and unpaid compensation and, to the extent not otherwise paid, a prorated annual bonus and (ii) a severance payment equal to 2.99 times the sum of such officer’s (a) annual base salary and (b) highest recent annual bonus. The officer also is entitled to continued welfare benefits for three years and outplacement services. If the payment of these benefits, when taken together with any other payments to the officer, would result in the imposition of the excise tax on excess parachute payments under Section 4999 of the Code, then the severance benefits will be reduced to the extent where no excise tax would be payable if such reduction results in a greater after-tax payment to the officer. The officer is entitled to receive such amounts in a lump-sum payment within 30 days of termination. For these purposes, good reason means (i) a diminution in the officer’s position, authority, duties or responsibilities, (ii) a failure by the Company to comply with specified provisions of the employment agreement, (iii) the officer is required to be based at a different office or location 50 miles or more away or is required to travel to a substantially greater extent, and (iv) any purported termination by the Company of the officer’s employment other than as expressly permitted by the employment agreement. In addition, a termination by the officer for any reason during the 30-day period following the first anniversary of the change of control will be deemed a termination for good reason.

 

Assuming that a change of control had occurred and the named executive officers were terminated on December 31, 2006 and that the price of OGE Energy’s Common Stock was $40.00 (the closing price on December 29, 2006, the last business day of 2006), then the named executive officers would be entitled to the following lump sum severance payments under their employment agreements: S.E. Moore, $3,105,017; P.B. Delaney, $1,875,287; J.R. Hatfield, $1,330,325; D.P. Harris, $940,401; and S.R. Gerdes, $713,809. For these purposes, we have assumed that the payments would not result in the imposition of the excise tax on excess parachute payments, which if triggered, could result in a reduction of the foregoing amounts. The named executive officers would also be entitled to outplacement services, valued at approximately $50,000 each, and continued welfare benefits for three years at a value of approximately $31,000 each. For these purposes we have assumed that health care costs will increase at the rate of 9% per year. These officers also would be entitled to the retirement benefits they would otherwise be entitled to receive as set forth in the Pension Benefits table on page 26 and, as described above, Mr. Delaney would be considered vested under the SERP. Finally, matching credits under the nonqualified deferred compensation plan would vest and the officers would be entitled to the benefits set forth in the Nonqualified Deferred Compensation table on page 28.

 

In addition, pursuant to the terms of the Company’s incentive compensation plans, upon a change of control, all stock options and restricted stock will vest immediately and, for a 60-day period following the change of control, executive officers may surrender their options and receive in return a cash payment equal to the excess of the change of control price (as defined) over the exercise price; all performance units will vest and be paid out

 

 

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immediately in cash as if the applicable performance goals had been obtained at target levels; and any annual incentive award outstanding at the participant’s termination for any reason other than cause within 24 months after the change of control will be paid in cash at target level on a prorated basis. Although all outstanding stock options are already exercisable, upon a change of control, executive officers could surrender their options and receive a cash payment equal to the excess of the change of control price over the exercise price. Assuming that a change of control occurred on December 31, 2006 and that the price of our common stock (and the change of control price) was $40.00 (the closing price on December 29, 2006, the last business day of 2006), then the named executive officers would be entitled to the following lump sum payments for outstanding stock options and performance unit awards: S.E. Moore, $22,548,737; P.B. Delaney, $6,789,398; J.R. Hatfield, $1,955,874; D.P. Harris, $1,183,302; and S.R. Gerdes, $685,278.

 

If a named executive officer terminates employment other than following a change of control, such officer will be entitled to receive amounts earned during the course of his or her employment, including accrued salary and unpaid salary and unused vacation pay. If the termination was a result of death, disability or retirement, the executive officer could exercise his or her stock options generally for three years or their stated term, if less, and would be entitled to a regular payout of any earned annual and long-term awards whose performance periods had ended prior to the individual’s termination, and to a pro-rated payout (based on the individual’s number of full months of employment during the applicable performance period) for other outstanding annual and long-term incentive awards when and if payouts of such awards are subsequently earned and are made to participants who did not terminate their employment. Assuming that the named executive officers terminated their employment as a result of death, disability or retirement on December 31, 2006, each executive officer would have received the same payout of the earned annual incentive compensation for 2006 that is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 23 and the same payout of long-term compensation for the performance units whose three-year performance period ended December 31, 2006 as reflected in the Stock Awards - Value Realized on Vesting column in the Option Exercises and Stock Vested Table on page 26. The reason for the same payouts is that the individual would have been employed throughout the entire performance period for the awards. If the named executive officer elects to exercise his options at the time of termination and, assuming that the price of our common stock was $40.00 (the closing price on December 29, 2006, the last business day of 2006), then the value realized on the exercise of the options for the named executive officers would be as follows: S.E. Moore, $15,822,537; P.B. Delaney, $3,198,678; J.R. Hatfield, $231,074; D.P. Harris, $465,542; and S.R. Gerdes, $53,118. In addition, for the outstanding grants of performance units whose performance periods end on December 31, 2007 and December 31, 2008 and assuming that the named executive officers terminated their employment as a result of death, disability or retirement on December 31, 2006, that the applicable goals for such performance units were subsequently satisfied at target levels and that the price of OGE Energy’s Common Stock was $40.00 (the closing price on December 29, 2006, the last business day of 2006) at the time payouts of such performance units occurred, then the named executive officers would be entitled to receive Common Stock of the Company having the following values at the time payout of such performance units occurred: S.E. Moore, $1,261,360 for the performance units whose performance period ends December 31, 2007 and $790,520 for the performance units whose performance period ends December 31, 2008; P.B. Delaney, $718,960 for the performance units whose performance period ends December 31, 2007 and $413,480 for the performance units whose performance period ends December 31, 2008; J.R. Hatfield, $317,880 for the performance units whose performance period ends December 31, 2007 and $212,880 for the performance units whose performance period ends December 31, 2008; D.P. Harris, $135,640 for the performance units whose performance period ends December 31, 2007 and $105,520 for the performance units whose performance period ends December 31, 2008; and S.R. Gerdes, $135,640 for the performance units whose performance period ends December 31, 2007 and $49,640 for the performance units whose performance period ends December 31, 2008.

 

In addition to the benefits described above, upon retirement, the executive officers will be entitled to receive the retirement benefits described in the Pension Benefits table on page 26 and the nonqualified deferred compensation benefits set forth in the Nonqualified Deferred Compensation table on page 28 as well as lifetime retiree medical benefits if they were hired prior to February 1, 2000 and noncontributory lifetime retiree life insurance at 60% of pre-retirement levels but not more than $20,000 or less than $10,000.

 

 

 

 

 

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SECURITY OWNERSHIP

 

The following table shows the number of shares of the Company’s Common Stock beneficially owned on March 1, 2007, by each Director, by each of the Executive Officers named in the Summary Compensation Table on page 23, and by all Executive Officers and Directors as a group:

 

 

 

The information on share ownership is based on information furnished to us by the individuals listed above and all shares listed are beneficially owned by the individuals or by members of their immediate family unless otherwise indicated.

 

EQUITY COMPENSATION PLAN INFORMATION

 

The following table provides certain information as of December 31, 2005 with respect to the shares of the Company’s Common Stock that may be issued under the existing equity compensation plans:

 

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SECTION 16(a) BENEFICIAL OWNERSHIP

REPORTING COMPLIANCE

 

Under federal securities laws, our directors and executive officers are required to report, within specified dates, their initial ownership in the Company’s Common Stock and subsequent acquisitions, dispositions or other transfers of interest in such securities. We are required to disclose whether we have knowledge that any person required to file such a report may have failed to do so in a timely manner. To our knowledge, all of our officers and directors subject to such reporting obligations satisfied their reporting obligations in full in 2006.

 

SHAREOWNER PROPOSALS

 

Any shareowner proposal intended to be included in the proxy statement for the Annual Meeting in 2008 must be received by the Company on or before November 30, 2007. Proposals received by that date, deemed to be proper for consideration at the Annual Meeting and otherwise conforming to the rules of the SEC, will be included in the 2008 proxy statement.

 

If you intend to submit a shareowner proposal for consideration at the Annual Meeting, but do not want it included in the proxy statement, you must follow the procedures established by our By-laws. These procedures require that you notify us in writing of your proposal. Your notice must be received by the Corporate Secretary at least 90 days prior to the meeting and must contain the following information:

 

 

 

 

 

HOUSEHOLDING INFORMATION

 

We have adopted a procedure approved by the SEC called “householding.” Under this procedure, certain shareowners of record who have the same address and last name and do not participate in electronic delivery of proxy materials will receive only one copy of our Summary Annual Report to Shareowners and proxy statement, unless one or more of these shareowners notifies us that they would like to continue to receive individual copies. This will reduce our printing costs and postage fees. Shareowners who participate in householding will continue to receive separate proxy cards. Also, householding will not in any way affect dividend check or dividend reinvestment statement mailings.

 

If you and other shareowners of record with whom you share an address currently receive multiple copies of our Summary Annual Report to Shareowners and/or proxy statement, or if you hold stock in more than one account, and in either case, you would like to receive only a single copy of the Summary Annual Report to Shareowners or proxy statement for your household, please contact Mellon Investor Services; P.O. Box 3338, South Hackensack, NJ 07606 or phone toll free 1-888-216-8114.

 

If you participate in householding and would like to receive a separate copy of our Summary Annual Report to Shareowners or this proxy statement, please call us at 405-553-3211 or write us at: OGE Energy Corp. Shareowner Relations, 321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101-0321. We will deliver the requested documents to you promptly upon receipt of your request.

 

Some banks, brokers and other nominee record holders may be participating in the practice of “householding” proxy statements and annual reports. This means that only one copy of our proxy statement or Summary Annual Report to Shareowners may have been sent to multiple shareowners in your household. We will promptly deliver a separate copy of either document to you if you call us at 405-553-3211 or write us at: OGE Energy Corp. Shareowner Relations, 321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101-0321. If you want to receive separate copies of the Summary Annual Report to Shareowners and proxy statement in the future, or if you are receiving multiple copies and would like to receive only one copy for your household, you should contact your bank, broker, or other nominee record holder.

 

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LOCATION OF THE NATIONAL COWBOY AND WESTERN HERITAGE MUSEUM

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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OGE Energy Corp.

 

2006 Management’s

Discussion and Analysis

 

Appendix A to the Proxy Statement

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Introduction

 

OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments.

 

The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

 

The operations of the Natural Gas Pipeline segment are conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consist of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing of natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. In May 2006, Enogex Gas Gathering, L.L.C. (“Gathering”), a wholly-owned subsidiary of Enogex Inc., sold certain gas gathering assets in the Kinta, Oklahoma, area, which have been reported as discontinued operations in the Company’s Consolidated Financial Statements (see “Results of Operations – Enogex – Discontinued Operations” for a further discussion). In December 2006, Enogex entered into a joint venture arrangement with a third party. The joint venture, Atoka Midstream LLC, intends to construct, own and operate a gathering system and processing plant and related facilities relating to production in certain areas in southeastern Oklahoma. Enogex holds its 50 percent membership interest in Atoka Midstream LLC through Enogex Atoka LLC (“Enogex Atoka”), a wholly-owned subsidiary of Enogex Inc. Enogex Atoka will act as the managing member and operator of  the facilities owned by the joint venture.

 

Executive Overview

 

The Company’s vision is to be a regional utility-focused energy business recognized for operational excellence and strong financial performance. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream gas business. As explained below, the Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth, maintenance of a dividend payout ratio consistent with its peer group, maintenance of strong credit ratings and appropriate returns on invested capital. The Company believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

 

OG&E has been focused on its Customer Savings and Reliability Plan, which provides for increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment, replace aging transmission and distribution system and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, OG&E purchased, for approximately $160 million, a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) in July 2004. Capacity payment savings from reduced cogeneration payments and fuel savings from the McClain Plant will be utilized to help mitigate the price increases associated with this investment. Also, as part of this plan, on February 20, 2006, OG&E entered into an agreement to engineer, procure and construct a wind generation energy system for a 120 MW wind farm (“Centennial”) in northwestern Oklahoma. The wind farm was fully in service in January 2007. Through December 31, 2006, OG&E has spent approximately $171.1 million related to the Centennial wind farm. On January 17, 2007, OG&E sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. OG&E has announced a six-year construction initiative that is estimated to include up to $3.3 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. The first part of this initiative involved OG&E entering into an agreement for the proposed construction of a 950 MW coal unit at OG&E’s existing Sooner plant location near Red Rock, Oklahoma. OG&E expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. OG&E’s share of the projected $1.8 billion construction cost for the plant will be about $759 million. OG&E’s

 

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six-year construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure. Other projects involve installing new emission-control equipment at existing OG&E power plants to help meet OG&E’s commitment to meet environmental requirements. OG&E also expects to incur a significant amount of capital and operating expenditures in the next several years to comply with current and future environmental laws and regulations. For additional information regarding the above items and other regulatory matters, see Note 18 of Notes to Consolidated Financial Statements.

 

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. In August 2006, Enogex completed a project to expand its gathering pipeline capacity on the west side of its system in western Oklahoma and the Texas Panhandle that should enable Enogex to benefit from growth opportunities in that marketplace. Enogex continues to consider additional opportunities to expand this project. In addition to focusing on growing its earnings, Enogex has reduced its exposure to changes in commodity prices and minimized its exposure to keep-whole processing arrangements. Enogex’s profitability increased significantly from 2003 to 2006 due to the performance improvement plan initiated in 2002 as well as an overall favorable business environment coupled with higher commodity prices. While the Company believes substantial progress has been achieved, additional opportunities remain. Enogex continues to review its work processes, evaluate the rationalization of assets, negotiate better terms for both new contracts and replacement contracts, manage costs and pursue opportunities for organic growth, all in an effort to further improve its cash flow and net income, while at the same time decreasing the volatility associated with commodity prices. Enogex’s marketing business, which concentrates principally on origination of physical sales of natural gas, has expanded into the Gulf Coast and Rocky Mountain markets. Also, Enogex’s marketing business utilizes a strategy that seeks to minimize the amount of capital employed and to complement better the natural gas pipeline business. The Company expects to continue to pursue a disciplined approach to continuous improvement and efficiency of operations. Also, during 2005 and 2006, Enogex sold its interests in Enogex Arkansas Pipeline Corporation (“EAPC”) and Enerven Compression Services, LLC (“Enerven”) and certain gas gathering assets in the Kinta, Oklahoma area (the “Kinta Assets”) and will continue to review its asset portfolio and seek to divest underperforming or non-strategic assets. Also, on December 15, 2006, Enogex announced that it had entered into a firm capacity lease agreement with Midcontinent Express Pipeline, LLC for a primary term of 10 years (subject to possible extensions) for certain capacity on the Enogex system. The leased capacity provided for in this agreement is up to 0.5 billion cubic feet (“Bcf”) per day and is dependent on the shipper volumes that commit to the project. The Enogex capacity will be part of the proposed Midcontinent Express Pipeline (“MEP”), a joint venture between Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. In addition to the Enogex leased capacity, the proposed MEP project includes a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Pending necessary regulatory approval, the MEP pipeline project is currently expected to be in service by February 2009. Depending on the final capacity that MEP subscribes to pursuant to the agreement, Enogex expects its revenues from this firm capacity lease agreement to be between $12 million and $30 million annually. Enogex currently estimates that its capital expenditures related to this project during the next two to three years could be approximately $100 million. The Enogex lease agreement with the MEP is subject to certain contingencies including regulatory approval. Prior to such approval, Enogex may incur expenditures of between approximately $20 million and $40 million with the majority being for certain commitments for materials that can be sold or used in normal operations in the event the MEP project does not proceed and the amount not recovered or utilized for such expenditures is not expected to be material. Enogex also is seeking to provide lease capacity to Boardwalk’s Gulf Crossings project. Boardwalk Pipeline Partners, LP, has announced plans to build the Gulf Crossings pipeline, which includes 355 miles of new interstate natural gas pipeline. It initially is expected to transport gas from the supply areas in Sherman, Texas, Bennington, Oklahoma and Paris, Texas to the Perryville, Louisiana Hub. Subject to regulatory approvals, the Gulf Crossings project is expected to be in service during the fourth quarter of 2008.

 

The Company’s business strategy is to continue maintaining the diversified asset position of OG&E and Enogex so as to provide competitive energy products and services to customers primarily in the south central United States. The Company will continue to focus on those products and services with limited or manageable commodity exposure. In addition to the incremental growth opportunities that Enogex provides, the Company believes that many of the risk management practices, commercial skills and market information available from Enogex provide value to all of the Company’s businesses.

 

In December 2006, the Company and OG&E increased their aggregate available borrowing capacity under their revolving credit agreements from $750.0 million to $1.0 billion, $600 million for the Company and $400 million for OG&E. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods. Also, each of these credit facilities has an additional option at the end of the two renewal options to convert the outstanding balance to a one-year term loan. These revolving credit agreements will provide sufficient liquidity to meet the Company’s daily operational needs, capital improvements at OG&E and expansion projects at Enogex.

 

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Overview

 

Summary of Operating Results

 

2006 compared to 2005. The Company reported net income of approximately $262.1 million, or $2.84 per diluted share, in 2006 as compared to approximately $211.0 million, or $2.32 per diluted share, in 2005. The increase in net income during 2006 as compared to 2005 was primarily due to:

 

 

2005 compared to 2004. The Company reported net income of approximately $211.0 million, or $2.32 per diluted share, in 2005 as compared to approximately $153.5 million, or $1.73 per diluted share, in 2004. The increase in net income during 2005 as compared to 2004 was primarily due to:

 

 

Recent Developments

 

OG&E Wind Power Filing

 

As discussed above, in January 2007, the Centennial wind farm in northwestern Oklahoma was fully in service. Through December 31, 2006, OG&E has spent approximately $171.1 million related to the Centennial wind farm. The OCC previously had approved a settlement agreement approving the Centennial wind power contract and a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. The settlement also indicated that OG&E shall file for a general rate review during 2009 that will permit the OCC to issue an order no later than December 31, 2009 placing the Centennial wind farm in OG&E’s rate base. On January 17, 2007, OG&E sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. The recovery rider is designed to recover approximately $22.6 million in the first year of operations, which amount will decline over the life of the facility. Because the wind farm rider was implemented in February 2007, OG&E expects to recover approximately $20.7 million under the rider during the remaining 11 months of 2007. OG&E expects the recovery rider to remain in effect through late 2009. As explained below, the recent rate order from the APSC allows for the recovery of the portion of the Centennial wind farm allocable to OG&E’s customers in Arkansas.

 

OG&E Arkansas Rate Case Filing

 

On July 28, 2006, OG&E filed with the APSC an application for an annual rate increase of approximately $13.5 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant, the Centennial wind power project and the costs of electric system expansion and upgrades based on a return on equity of 11.75 percent. On November 29, 2006, OG&E reached a settlement with the other parties in this case for an annual rate increase of approximately $5.4 million. In the settlement agreement, the parties also agreed that OG&E would be allowed to recover the full Arkansas portion of the Centennial wind farm. On January 5, 2007, the APSC approved the settlement and issued a rate

 

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order that provides for a $5.4 million annual increase in OG&E’s electric rates and a 10.0 percent return on equity. The new Arkansas rates became effective in February 2007.

 

Proposed Construction of Power Plant

 

As discussed above, OG&E has entered into a contract with American Electric Power’s subsidiary, Public Service Company of Oklahoma (“PSO”), and the Oklahoma Municipal Power Authority (“OMPA”) to build a new 950 MW coal unit at OG&E’s existing Sooner plant location near Red Rock, Oklahoma. The estimated $1.8 billion project is the result of PSO’s December 2005 request for proposals in which it sought bids for up to 600 MW’s of new base load generation to be available to PSO. The unit, to be called Red Rock, is expected to be one of the cleanest of its size using coal from the Powder River Basin, which is located near Gillette, Wyoming. OG&E will operate the facility and expects to spend approximately $759 million in construction costs related to its 42 percent ownership percentage in the project and approximately $30 million in transmission costs for the project. PSO will own 50 percent and the OMPA will own eight percent. On December 1, 2006, OG&E submitted an application to the Oklahoma Department of Environmental Quality (“ODEQ”) for an air permit for the Red Rock plant. OG&E is seeking to have the air permit approved by the ODEQ by August 1, 2007. OG&E expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. OG&E filed an application with the OCC on January 17, 2007 asking the OCC to find that its portion of the construction costs are prudent and that a recovery mechanism should be established to recover OG&E’s overall cost of capital on the investment during the construction period. The OCC rules provide that the OCC has up to 240 days to issue an order determining OG&E’s pre-approval request, however OG&E’s application requested that the OCC issue an order by July 20, 2007. The project is contingent upon numerous factors, including the successful completion of contract negotiations and the necessary regulatory and environmental approvals. Under the construction, ownership and operating agreement between OG&E, PSO and the OMPA, the parties could incur up to $60 million (of which approximately $25 million would be borne by OG&E) prior to the receipt of acceptable regulatory approvals and permits. If such approvals and permits were not obtained and the Red Rock project was abandoned, the Company can provide no assurance that these expenditures incurred by OG&E would be recoverable in future rates.

 

Enogex Expansion Projects

 

In August 2006, Enogex completed a project to expand its gathering pipeline capacity on the west side of its system in western Oklahoma and the Texas Panhandle that should enable Enogex to benefit from growth opportunities in that marketplace. Enogex continues to consider additional opportunities to expand this project.

 

Termination of Continental Connector Project

 

Enogex had previously announced that it had entered into a letter of intent with El Paso Corporation (“El Paso”) relating to El Paso’s Continental Connector Project. The letter of intent contemplated arrangements by which El Paso or an affiliate would execute a lease of capacity on the Enogex pipeline system and the leased Enogex pipeline capacity would become part of the Continental Connector Project. The letter of intent expired on April 28, 2006. In early October 2006, El Paso determined not to proceed with its proposed Continental Connector project. Enogex did not incur any material expenditures relating to this proposed project.

 

Oklahoma City Dayton Tire Plant Closing

 

In July 2006, the Boards of Directors of Bridgestone Firestone North American Tire and its parent company, Bridgestone Americas Holding Inc., approved the closing of the Oklahoma City Dayton tire plant, which closed in December 2006. The closing of this plant is expected to reduce net income by approximately $1.1 million, or $0.01 per diluted share, in 2007.

 

2007 Outlook

 

The Company previously disclosed in its Form 10-Q for the quarter ended September, 2006 that its 2007 earnings guidance was $213 million to $231 million of income from continuing operations, or $2.30 to $2.50 per diluted share. The Company has reaffirmed the 2007 earnings guidance, which excludes any gains on asset sales and assumes approximately 92.5 million average diluted shares outstanding and an effective tax rate of 32.6 percent. The Company is currently projecting earnings toward the lower half of the guidance due to refinements of its prior estimates based on its 2006 audited financial results and numerous other factors. At the utility, these factors include reduced tariffs for fuel-related costs, the slight delay in implementing the Centennial wind farm rider and increased depreciation expense, offset in part by higher anticipated margin growth. At Enogex, a key factor was the recognition of mark-to-market gains in the marketing business in

 

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the fourth quarter of 2006 that were previously anticipated for the first quarter of 2007. Projected cash flow from operations of between $371 million and $389 million for 2007 has been lowered to $336 million to $354 million primarily due to the collection by OG&E during 2006 under approved tariffs of approximately $26.7 million of additional fuel-related revenues that was not intended by the OCC rate order in December 2005. The $26.7 million, plus interest, will be credited to OG&E’s Oklahoma customers in 2007 and 2008 through OG&E’s automatic fuel adjustment clause and reduced tariffs were filed, effective December 31, 2006, that will cease the continued recovery of these additional fuel-related revenues. See “Financial Condition” below.

 

 

Key assumptions for 2007 are:

 

As shown above, OG&E’s earnings guidance has been reaffirmed at $154 million to $162 million. Key factors and assumptions underlying this guidance include:

 

OG&E

 

 

OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings or slight losses in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

 

Enogex

 

As shown above, Enogex’s earnings guidance remains unchanged from $63 million to $72 million, or $0.68 to $0.78 per diluted share. Key factors and assumptions underlying this guidance include:

 

 

 

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Enogex expects to continue to evaluate the strategic fit and financial performance of each of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been included in the 2007 earnings guidance.

 

Holding Company

 

As shown above, the projected loss at the holding company is $3 million to $4 million, or $0.03 to $0.05 per diluted share, primarily due to projected interest costs.

 

Dividend Policy

 

The Company’s dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends no more than 65 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. At the Company’s November 2006 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.34 per share from $0.3325 per share payable in the first quarter of 2007.

 

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Results of Operations

 

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the years ended December 31, 2006, 2005 and 2004 and the Company’s consolidated financial position at December 31, 2006 and 2005. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

 

 

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Consolidated Statements of Income as operating income indicates the ongoing profitability of the Company excluding unusual or infrequent items, the cost of capital and income taxes.

 

Operating Income (Loss) by Business Segment

 

(A) Other Operations primarily includes unallocated corporate expenses and consolidating eliminations.

 

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.

 

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OG&E

 

 

 

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2006 compared to 2005. OG&E’s operating income increased approximately $61.7 million or 26.7 percent in 2006 as compared to 2005 primarily due to higher gross margins partially offset by higher operating expenses.

 

Gross margin, which is operating revenues less cost of goods sold, was approximately $795.7 million in 2006 as compared to approximately $726.5 million in 2005, an increase of approximately $69.2 million, or 9.5 percent. The gross margin increased primarily due to:

 

 

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $730.3 million in 2006 as compared to approximately $795.4 million in 2005, a decrease of approximately $65.1 million or 8.2 percent due to lower natural gas prices. OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2006 and 2005, respectively, OG&E’s fuel mix was 67 percent coal and 33 percent natural gas and 70 percent coal and 30 percent natural gas. Though OG&E has a higher installed capability of generation from natural gas units of 57 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $219.7 million in 2006 as compared to approximately $198.8 million in 2005, an increase of approximately $20.9 million or 10.5 percent. This increase was primarily due to a power purchase contract that allowed OG&E to make economic purchases during peak demand summer months.

 

Other operating and maintenance expenses were approximately $316.5 million in 2006 as compared to approximately $309.2 million in 2005, an increase of approximately $7.3 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

 

 

 

 

The other operating and maintenance expense variance includes other operating and maintenance expenses associated with the acquisition of the McClain Plant, which expenses ceased being recorded as a regulatory asset on July 8, 2005.

 

Depreciation expense was approximately $132.2 million in 2006 as compared to approximately $134.4 million in 2005, a decrease of approximately $2.2 million or 1.6 percent. The decrease in depreciation expense was primarily due to:

 

 

These decreases in depreciation expense were partially offset by a full year of depreciation expense in 2006 associated with the acquisition of the McClain Plant.

 

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Taxes other than income were approximately $53.1 million in 2006 as compared to approximately $50.7 million in 2005, an increase of approximately $2.4 million or 4.7 percent, primarily due to increased ad valorem taxes. This variance includes ad valorem taxes associated with the acquisition of the McClain Plant, which expenses ceased being recorded as a regulatory asset on July 8, 2005.

 

Allowance for equity funds used during construction was approximately $4.1 million in 2006 due to construction costs associated with OG&E’s Centennial wind farm that exceeded the average daily short-term borrowings in 2006. There was no allowance for equity funds used during construction in 2005.

 

Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $4.0 million in 2006 as compared to a reduction in other income of approximately $2.8 million in 2005, an increase in other income of approximately $6.8 million. The increase in other income was primarily due to:

 

 

Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $9.7 million in 2006 as compared to approximately $2.5 million in 2005, an increase of approximately $7.2 million primarily due to a loss on the retirement of fixed assets of approximately $6.0 million.

 

Interest expense was approximately $60.1 million in 2006 as compared to approximately $47.2 million in 2005, an increase of approximately $12.9 million or 27.3 percent. The increase in interest expense was primarily due to:

 

 

These increases in interest expense were partially offset by:

 

 

Income tax expense was approximately $84.8 million in 2006 as compared to approximately $52.6 million in 2005, an increase of approximately $32.2 million or 61.2 percent. The increase in income tax expense was primarily due to:

 

 

2005 compared to 2004. OG&E’s operating income increased approximately $39.9 million or 20.7 percent in 2005 as compared to 2004 primarily attributable to higher gross margins partially offset by higher operating expenses.

 

Gross margin was approximately $726.5 million in 2005 as compared to approximately $663.9 million in 2004, an increase of approximately $62.6 million or 9.4 percent. The gross margin increased primarily due to:

 

 

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Fuel expense was approximately $795.4 million in 2005 as compared to approximately $645.1 million in 2004, an increase of approximately $150.3 million or 23.3 percent. The increase was primarily due to increased generation and a higher average cost of fuel per kwh. OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2005 and 2004, OG&E’s fuel mix was 70 percent coal and 30 percent natural gas. Though OG&E has a higher installed capability of generation from natural gas units of 58 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $198.8 million in 2005 as compared to approximately $269.1 million in 2004, a decrease of approximately $70.3 million or 26.1 percent. The decrease was primarily due to OG&E’s completion of the acquisition of the McClain Plant in 2004, the termination of a power purchase contract in August 2004 which was replaced with a new contract in September 2004 and the scheduled decrease in cogeneration capacity payments for another power purchase contract, which became effective in January 2005.

 

Other operating and maintenance expenses were approximately $309.2 million in 2005 as compared to approximately $301.9 million in 2004, an increase of approximately $7.3 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

 

 

These increases in other operating and maintenance expenses were partially offset by lower allocations from the holding company of approximately $6.9 million primarily due to lower miscellaneous corporate expenses. This variance includes other operating and maintenance expenses associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

 

Depreciation expense was approximately $134.4 million in 2005 as compared to approximately $122.7 million in 2004, an increase of approximately $11.7 million or 9.5 percent, primarily due to a higher level of depreciable plant in addition to depreciation expense associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

 

Taxes other than income were approximately $50.7 million in 2005 as compared to approximately $47.0 million in 2004, an increase of approximately $3.7 million or 7.9 percent, primarily due to increased ad valorem taxes. This variance includes ad valorem taxes associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

 

There was a reduction in other income of approximately $2.8 million in 2005 as compared to income of approximately $4.5 million in 2004, a decrease of approximately $7.3 million. The decrease in other income was primarily due to gains recognized in 2004 of approximately $3.5 million from the sale of OG&E’s interests in its natural gas producing properties and the sale of land near the Company’s principal executive offices which gains were reversed in 2005 and reclassified to Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheet as a regulatory liability. Also contributing to the decrease in other income was a gain in 2004 of approximately $0.6 million from the repurchase of outstanding heat pump loans.

 

Interest expense was approximately $47.2 million in 2005 as compared to approximately $37.5 million in 2004, an increase of approximately $9.7 million or 25.9 percent. The increase in interest expense was primarily due to:

 

 

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Income tax expense was approximately $52.6 million in 2005 as compared to approximately $53.0 million in 2004, a decrease of approximately $0.4 million or 0.8 percent. The decrease in income tax expense was primarily due to:

 

 

 

Enogex – Continuing Operations

 

(A) Excludes wells behind central receipt points.

(B) Trillion British thermal units per day.

 

2006 compared to 2005. Enogex’s operating revenues and cost of goods sold decreased in 2006 approximately $2.0 billion, or 45.4 percent, and $2.0 billion, or 49.6 percent, respectively, as compared to 2005 primarily due to a lower level of trading activity due to a shift in strategy in Enogex’s marketing business. Enogex’s operating income increased approximately $49.2 million in 2006 as compared to 2005 primarily due to increased gross margins in each of Enogex’s

 

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businesses largely as a result of higher commodity spreads and business growth in 2006 as compared to 2005. The increases in gross margin were partially offset by higher operating and maintenance expenses.

 

Transportation and storage contributed approximately $125.6 million of Enogex’s gross margin in 2006 as compared to approximately $99.1 million in 2005, an increase of approximately $26.5 million or 26.7 percent. The gross margin increased primarily due to:

 

 

These increases in the transportation and storage gross margin were partially offset by a lower of cost or market adjustment related to natural gas inventory used to operate the pipeline during 2006, which reduced the 2006 gross margin by approximately $8.3 million as there was no comparable item during 2005.

 

Gathering and processing contributed approximately $167.6 million of Enogex’s gross margin in 2006 as compared to approximately $140.2 million in 2005, an increase of approximately $27.4 million or 19.5 percent. The gathering and processing gross margin increased primarily due to:

 

 

These increases in the gathering and processing gross margin were partially offset by the recognition of imbalance expense in 2006 (previously carried by the transportation and storage business in 2005), which reduced the gross margin by approximately $13.8 million in 2006.

 

Marketing contributed approximately $14.2 million of Enogex’s gross margin in 2006 as compared to approximately $2.7 million in 2005, an increase of approximately $11.5 million. The gross margin increased primarily due to:

 

 

 

 

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Enogex’s other operating and maintenance expenses were approximately $110.0 million in 2006 as compared to approximately $96.6 million in 2005, an increase of approximately $13.4 million or 13.9 percent. The increase in other operating and maintenance expenses was primarily due to:

 

 

These increases in other operating and maintenance expenses were partially offset by a sales and use tax refund of approximately $2.0 million received in May 2006 related to activity in prior years.

 

Depreciation expense was approximately $42.3 million in 2006 as compared to approximately $40.4 million during the same period in 2005, an increase of approximately $1.9 million or 4.7 percent, primarily due to new assets placed into service during 2006.

 

Interest income was approximately $11.1 million in 2006 as compared to approximately $2.9 million in 2005, an increase of approximately $8.2 million primarily due to interest income on cash investments from interest earned on the cash proceeds from the sale of EAPC in October 2005 and the sale of the Kinta Assets in May 2006.

 

Other income was approximately $7.7 million in 2006 as compared to approximately $0.8 million in 2005, an increase of approximately $6.9 million. The increase in other income was primarily due to:

 

 

Income tax expense was approximately $48.0 million in 2006 as compared to approximately $20.4 million in 2005, an increase of approximately $27.6 million primarily due to higher pre-tax income for Enogex.

 

For 2006, Enogex’s net income, including the discontinued operations discussed below under the caption “Enogex – Discontinued Operations,” was approximately $113.5 million. During 2006, Enogex had an increase in net income of approximately $41.2 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. These increases in net income include:

 

 

These increases in net income were partially offset by a decrease in net income of approximately $0.2 million related to the impairment of certain long-lived assets.

 

For 2005, Enogex’s net income, including the discontinued operations discussed below under the caption “Enogex – Discontinued Operations,” was approximately $89.8 million. During 2005, Enogex had an increase in net income of approximately $45.3 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. These increases in net income include:

 

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These increases to net income were partially offset by a correction to the accounting procedure for park and loan transactions in 2005 of approximately $4.7 million.

 

2005 compared to 2004. Enogex’s operating income decreased approximately $13.7 million in 2005 as compared to 2004 primarily due to decreased gross margins in Enogex’s marketing business and Enogex’s transportation and storage business, which were partially offset by increased gross margins in Enogex’s gathering and processing business. The overall decrease in gross margins was partially offset by an asset impairment charge of approximately $7.8 million recorded in 2004 with no similar item recorded in 2005.

 

Transportation and storage contributed approximately $99.1 million of Enogex’s gross margin in 2005 as compared to approximately $114.5 million in 2004, a decrease of approximately $15.4 million or 13.4 percent. The gross margin decreased primarily due to:

 

 

 

 

Gathering and processing contributed approximately $140.2 million of Enogex’s gross margin in 2005 as compared to approximately $123.4 million in 2004, an increase of approximately $16.8 million or 13.6 percent. The gathering and processing gross margin increased primarily due to:

 

 

 

 

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Marketing contributed approximately $2.7 million of Enogex’s gross margin in 2005 as compared to approximately $23.8 million in 2004, a decrease of approximately $21.1 million or 88.7 percent. The gross margin decreased primarily due to:

 

 

 

 

Enogex’s other operating and maintenance expenses were approximately $96.6 million in 2005 as compared to approximately $93.5 million in 2004, an increase of approximately $3.1 million or 3.3 percent. The increase in other operating and maintenance expenses was primarily due to:

 

 

These increases in other operating and maintenance expenses were partially offset by an uncollectible debt reserve of approximately $1.1 million recorded in 2004 with no similar reserve recorded in 2005.

 

Impairment of assets was approximately $7.8 million ($4.8 million after tax) in 2004 as a result of recording an impairment charge during the third quarter of 2004. The impairment charge related to certain Enogex natural gas pipeline assets that served a particular customer’s power plants pursuant to a transportation agreement that was terminated by the customer effective December 31, 2004. There were no impairments recorded in 2005.

 

Interest income was approximately $2.9 million in 2005 as compared to approximately $3.2 million in 2004, a decrease of approximately $0.3 million or 9.4 percent, primarily due to a decrease in interest income of approximately $1.9 million due to the interest portion of an income tax refund related to prior periods which was received in 2004 with no similar activity recorded in 2005 partially offset by an increase in interest income of approximately $1.1 million from parent due to funds received from the sale of EAPC in October 2005.

 

Other income was approximately $0.8 million in 2005 as compared to approximately $4.5 million in 2004, a decrease of approximately $3.7 million or 82.2 percent. The decrease in other income was primarily due to a gain in 2004 of approximately $3.0 million from the sale of certain of Enogex’s compression and processing assets in 2004 in addition to approximately $0.8 million received related to a bankruptcy settlement from one of Enogex’s customers during the third quarter of 2004.

 

Income tax expense was approximately $20.4 million in 2005 as compared to approximately $29.4 million in 2004, a decrease of approximately $9.0 million or 30.6 percent. The decrease in income tax expense was primarily due to:

 

 

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These decreases in income tax expense were partially offset by a decrease in Oklahoma state income tax credits of approximately $1.6 million in 2005 as compared to 2004.

 

For 2005, Enogex’s net income, including the discontinued operations discussed below under the caption “Enogex – Discontinued Operations,” was approximately $89.8 million. During 2005, Enogex had an increase in net income of approximately $45.3 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. These increases in net income include:

 

 

These increases to net income were partially offset by a correction to the accounting procedure for park and loan transactions in 2005 of approximately $4.7 million.

 

For 2004, Enogex’s net income, including the discontinued operations discussed below under the caption “Enogex – Discontinued Operations,” was approximately $60.7 million. During 2004, Enogex had an increase in net income of approximately $15.6 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. These increases in net income include:

 

 

These increases to net income were partially offset by a net impairment charge of approximately $4.8 million.

 

Enogex – Discontinued Operations

 

In April 2005, Enogex Compression Company, LLC (“Enogex Compression”) received an unsolicited offer to buy its interest in Enerven, a joint venture focused on the rental of natural gas compression assets. After evaluating this offer, Enogex Compression sold its interest in Enerven for approximately $7.3 million in August 2005. Enogex Compression recognized an after tax gain of approximately $1.8 million related to the sale of this business.

 

Enogex regularly evaluates the long term stability, profitability and core competency of each of its businesses within the regulatory and market framework in which each business operates. Based on these evaluations, in September 2005, Enogex announced that it had entered into an agreement to sell its interest in EAPC, which held a 75 percent interest in the NOARK Pipeline System Limited Partnership. This sale was completed on October 31, 2005. The Company received approximately $177.4 million in cash proceeds and recognized an after tax gain of approximately $36.7 million from the sale of this business in the fourth quarter of 2005. Enogex used approximately $31.9 million of the proceeds to repay principal and accrued interest on long-term debt and approximately $46.7 million to pay taxes associated with EAPC. The balance of the proceeds of approximately $98.8 million, was used, among other things, to reduce short-term debt levels and fund capital expenditures.

 

In March 2006, Enogex announced that its wholly-owned subsidiary, Gathering, had entered into an agreement to sell certain gas gathering assets in the Kinta, Oklahoma, area. The Gathering assets included in the transaction were approximately 568 miles of gas gathering pipeline and 22 compressor units with current volumes of approximately 145 million cubic feet per day, all in eastern Oklahoma. The sale price was approximately $93 million. This transaction closed on May 1, 2006 and Enogex recorded an after tax gain of approximately $34.1 million during the second quarter of 2006. The proceeds from the sale, were used, among other things, to reduce short-term debt levels and fund capital expenditures.

 

As a result of these sale transactions, Enogex Compression’s interest in Enerven, Enogex’s interest in EAPC and Gathering’s Kinta Assets, which were part of the Natural Gas Pipeline segment, have been reported as discontinued operations for the years ended December 31, 2006, 2005 and 2004 in the Consolidated Financial Statements. Enogex Compression’s sale of its Enerven interest and Enogex’s sale of its EAPC interest were completed during 2005 and,

 

 

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therefore, there are no results of operations for these transactions during 2006. Results for these discontinued operations are summarized and discussed below.

 

 

2006 compared to 2005. Gross margin decreased approximately $32.0 million or 87.7 percent in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005, the sale of the Kinta Assets in May 2006 and a decrease in natural gas purchases and sales due to a decrease in natural gas transported prior to these assets being sold.

 

Operating and maintenance expense decreased approximately $6.5 million or 86.7 percent in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005 and the sale of the Kinta Assets in May 2006.

 

Depreciation expense decreased approximately $5.5 million or 94.8 percent in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005 and ceasing depreciation expense in January 2006 when the Kinta Assets were reported as a discontinued operation.

 

Taxes other than income decreased approximately $1.2 million or 92.3 percent in 2006 as compared to 2005 for ad valorem taxes primarily due to the sale of EAPC in October 2005.

 

Other income decreased approximately $10.2 million or 15.4 percent in 2006 as compared to 2005 due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

 

Interest expense decreased approximately $4.0 million or 100.0 percent in 2006 as compared to 2005 due to the sale of EAPC in October 2005 and the use of a portion of the sale proceeds to repay EAPC long-term debt.

 

Income tax expense increased approximately $11.3 million or 32.8 percent in 2006 as compared to 2005 primarily due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

 

2005 compared to 2004. Gross margin decreased approximately $3.6 million or 9.0 percent in 2005 as compared to 2004 primarily due to the sale of EAPC in October 2005 and a decrease in natural gas purchases and sales due to a decrease in natural gas transported prior to these assets being sold.

 

Other income increased approximately $66.2 million in 2005 as compared to 2004 due to a pre-tax gain of approximately $83.4 million recognized in the fourth quarter of 2005 related to the sale of EAPC and a pre-tax gain of approximately $2.9 million recognized in the third quarter of 2005 related to the sale of Enerven.

 

Interest expense decreased approximately $1.3 million or 24.5 percent in 2005 as compared to 2004 due to the sale of EAPC in October 2005 and the use of a portion of the sale proceeds to repay EAPC long-term debt.

 

Income tax expense increased approximately $27.4 million in 2005 as compared to 2004 primarily due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

 

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Financial Condition

 

The balance of Cash and Cash Equivalents was approximately $47.9 million and $26.4 million at December 31, 2006 and 2005, respectively, an increase of approximately $21.5 million or 81.4 percent, primarily due to proceeds received in October 2006 from the sale of Gathering’s Kinta Assets in May 2006.

 

The balance of Funds on Deposit was approximately $32.0 million at December 31, 2006 due to the Company making a deposit with the IRS on August 17, 2006 in anticipation that a portion of prior year deductions will be disallowed. The deposit enabled the Company to cease accruing interest effective August 17, 2006. See Note 10 of Notes to Consolidated Financial Statements for a further discussion.

 

The balance of Accounts Receivable, Net was approximately $344.3 million and $591.4 million at December 31, 2006 and 2005, respectively, a decrease of approximately $247.1 million or 41.8 percent, primarily due to lower natural gas sales prices and volumes by Enogex, a decrease in OG&E’s billings to its customers reflecting lower fuel costs in December 2006 as compared to December 2005 and payments received from other utilities for OG&E’s assistance with hurricanes Katrina and Rita.

 

The balance of current Price Risk Management assets was approximately $41.9 million and $116.5 million at December 31, 2006 and 2005, respectively, a decrease of approximately $74.6 million or 64.0 percent. The decrease was primarily due to lower natural gas prices associated with OGE Energy Resources, Inc. (“OERI”) short-term physical natural gas purchase transactions and associated financial contracts. A reduction in the volume of OERI’s short-term physical natural gas activity and associated financial contracts outstanding at December 31, 2006 from December 31, 2005 also contributed to the decrease.

 

The balance of Gas Imbalance asset was approximately $2.8 million and $32.0 million at December 31, 2006 and 2005, respectively, a decrease of approximately $29.2 million or 91.3 percent. The Gas Imbalance asset is comprised of planned or managed imbalances related to OERI’s business, referred to as park and loan transactions, and pipeline and natural gas liquids imbalances, which are operational imbalances. Park and loan transactions were approximately $15.7 million at December 31, 2005 with no comparable balance at December 31, 2006. The decrease in park and loan transactions was due to the expiration of 2005 park and loan transactions in OERI’s business activities. Operational imbalances were approximately $2.8 million and $16.3 million at December 31, 2006 and 2005, respectively, a decrease of approximately $13.5 million or 82.8 percent. The decrease in operational imbalances was primarily due to Enogex beginning to manage imbalances related to its storage operations on a combined basis in 2006 for its two storage facilities which resulted in a decrease in net imbalance volumes.

 

The balance of Construction Work in Progress was approximately $191.1 million and $101.8 million at December 31, 2006 and 2005, respectively, an increase of approximately $89.3 million or 87.7 percent, primarily due to construction expenditures related to OG&E’s Centennial wind farm in addition to construction expenditures related to the expansion of Enogex’s gathering pipeline capacity on the west side of its system in western Oklahoma and the Texas Panhandle.

 

The balance of Regulatory Asset – SFAS 158 was approximately $231.1 million at December 31, 2006 with no comparable balance at December 31, 2005. The balance of Intangible Asset – Unamortized Prior Service Cost was approximately $32.8 million at December 31, 2005 with no comparable balance at December 31, 2006. The balance of Prepaid Benefit Obligation was approximately $90.2 million at December 31, 2005 with no comparable balance at December 31, 2006. The change in these balances is due to the accounting change required upon adoption of SFAS No. 158, effective December 31, 2006, which required the Company to record the funded status of its pension and postretirement benefit plans on the Consolidated Balance Sheet (see Notes 1 and 2 of Notes to Consolidated Financial Statements for a further discussion).

 

The balance of Deferred Charges – Other was approximately $23.1 million and $7.2 million at December 31, 2006 and 2005, respectively, an increase of approximately $15.9 million, primarily due to the creation of a regulatory asset at OG&E of approximately $14.7 million for the excess pension expense over the amount granted in rates by the OCC in OG&E’s last Oklahoma rate case (see Note 1 of Notes to Consolidated Financial Statements for further discussion).

 

The balance of Short-Term Debt was approximately $30.0 million at December 31, 2005 with no comparable balance at December 31, 2006. The decrease was primarily due to proceeds received in October 2006 from the sale of Gathering’s Kinta Assets in May 2006 which were used to pay down the commercial paper balance.

 

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The balance of Accounts Payable was approximately $295.0 million and $510.4 million at December 31, 2006 and 2005, respectively, a decrease of approximately $215.4 million or 42.2 percent, primarily due to lower natural gas prices and volumes in December 2006 as compared to December 2005 and the timing of outstanding checks clearing the bank.

 

The balance of current Price Risk Management liabilities was approximately $9.2 million and $109.5 million at December 31, 2006 and 2005, respectively, a decrease of approximately $100.3 million or 91.6 percent. The decrease was primarily due to lower natural gas prices associated with OERI’s short-term physical natural gas purchase transactions and associated financial contracts. A reduction in the volume of OERI’s short-term physical natural gas activity and associated financial contracts outstanding at December 31, 2006 from December 31, 2005 also contributed to the decrease.

 

The balance of Gas Imbalance liability was approximately $11.1 million and $36.0 million at December 31, 2006 and 2005, respectively, a decrease of approximately $24.9 million or 69.2 percent. The Gas Imbalance liability is comprised of planned or managed imbalances related to OERI’s business, referred to as park and loan transactions, and pipeline and natural gas liquids imbalances, which are operational imbalances. Park and loan transactions were approximately $10.2 million at December 31, 2005 with no comparable balance at December 31, 2006. The decrease in park and loan transactions was due to the expiration of 2005 park and loan transactions in OERI’s business activities. Operational imbalances were approximately $11.1 million and $25.8 million at December 31, 2006 and 2005, respectively, a decrease of approximately $14.7 million or 57.0 percent. The decrease in operational imbalances was primarily due to Enogex beginning to manage imbalances related to its storage operations on a combined basis in 2006 for its two storage facilities which resulted in a decrease in net imbalance volumes.

 

The balance of Fuel Clause Over Recoveries was approximately $96.3 million at December 31, 2006. The balance of Fuel Clause Under Recoveries was approximately $101.1 million at December 31, 2005. The increase in fuel clause over recoveries was due to the amount billed to OG&E’s customers during 2006 exceeding OG&E’s cost of fuel due to lower than expected natural gas prices and amounts recovered under approved tariffs exceeding the amounts intended by the December 2005 OCC rate order. OG&E’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, OG&E typically under recovers fuel cost in periods of rising prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under or over recovery. As described in more detail in Note 18 of Notes to Consolidated Financial Statements, the OCC, in its order dated December 12, 2005, granted OG&E a $42.3 million annual increase in the rates charged by OG&E to its retail customers in Oklahoma. These increased rates became effective in January 2006 pursuant to approved tariffs filed with the OCC. In January 2007, OG&E determined that the approved tariffs had inadvertently authorized OG&E to collect, and OG&E had collected, approximately $26.7 million of additional fuel-related revenues during 2006 that was not intended by the December 12, 2005 order. As a result, OG&E filed with the OCC in January 2007 amendments to its previously-authorized tariffs, in order to cease recovery of the fuel-related revenues not intended by the December 12, 2005 order. The $26.7 million, plus $1.2 million of interest, was recorded as a liability under Fuel Clause Over Recoveries on the Consolidated Balance Sheet in the fourth quarter of 2006, and such amounts, along with other Fuel Clause Over Recoveries, will be credited to OG&E’s Oklahoma customers in 2007 and 2008 through OG&E’s automatic fuel adjustment clause. In addition, OG&E recorded a reduction in operating revenues of approximately $26.7 million and an increase in interest expense of approximately $0.5 million, which resulted in an after tax reduction in net income of approximately $16.7 million in the fourth quarter of 2006. Because the rate increase authorized in the December 2005 order was not implemented until January 2006 and the tariffs were corrected effective December 31, 2006, the $26.7 million had no impact on net income for the year ended December 31, 2006. See additional discussion in “Supplementary Data – Interim Consolidated Financial Information (Unaudited).”

 

Off-Balance Sheet Arrangements

 

Off-balance sheet arrangements include any transactions, agreements or other contractual arrangements to which an unconsolidated entity is a party and under which the Company has: (i) any obligation under a guarantee contract having specific characteristics as defined in Financial Accounting Standards Board (“FASB”) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”; (ii) a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets; (iii) any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument but is indexed to the Company’s own stock and is classified in stockholders’ equity in the Company’s consolidated balance sheet; or (iv) any obligation, including a contingent obligation, arising out of a variable interest as defined in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51,” in an unconsolidated entity that is held by, and material to, the Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing,

 

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hedging or research and development services with, the Company. The Company has the following material off-balance sheet arrangements.

 

OG&E Railcar Lease Agreement

 

OG&E leases more than 1,400 railcars used to deliver coal to OG&E’s coal-fired generation units. See Note 17 of Notes to Consolidated Financial Statements for a discussion of OG&E’s railcar lease agreement.

 

Liquidity and Capital Requirements

 

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and at Enogex. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage, delays in recovering unconditional fuel purchase obligations and fuel clause under and over recoveries. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

 

 

(A) Under current environmental laws and regulations, OG&E may be required to spend approximately $600 million in capital expenditures on its coal-fired plants. These expenditures are expected to begin in 2007 and would continue over the next five years.

(B) Includes expected recoveries of costs incurred for OG&E’s railcar operating lease obligations and OG&E’s unconditional fuel purchase obligations.

N/A – not available

 

Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the

 

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cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional fuel purchase obligations of OG&E noted above may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. See Note 18 of Notes to Consolidated Financial Statements for a discussion of the completed proceedings at the OCC regarding OG&E’s gas transportation and storage contract with Enogex.

 

2006 Capital Requirements and Financing Activities

 

Total capital requirements, consisting of capital expenditures, maturities of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $662.1 million and contractual obligations, net of recoveries through automatic fuel adjustment clauses, were approximately $10.7 million resulting in total net capital requirements and contractual obligations of approximately $672.9 million in 2006. Approximately $17.8 million of the 2006 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $448.8 million and net contractual obligations of approximately $4.3 million totaling approximately $453.1 million in 2005, of which approximately $19.2 million was to comply with environmental regulations. During 2006, the Company’s sources of capital were internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings and commercial paper) and proceeds from the sale of assets. The Company uses its commercial paper to fund changes in working capital and as an interim source of financing capital expenditures until permanent financing is arranged. Changes in working capital reflect the seasonal nature of the Company’s business, the revenue lag between billing and collection from customers and fuel inventories. See “Financial Condition” for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

 

Discontinued Operations

 

Also contributing to the liquidity of the Company has been the disposition of certain assets classified as discontinued operations in 2005 and 2006. During 2005 and 2006, these dispositions have generated net sales proceeds of approximately $277.6 million. Sales proceeds generated to date have been used to reduce short-term debt levels and fund capital expenditures.

 

Additional asset sales could further contribute to the liquidity of the Company.

 

Long-term Debt Maturities

 

Maturities of the Company’s long-term debt during the next five years consist of $3.0 million in 2007; $1.0 million in 2008 and $400.0 million in 2010. There are no maturities of the Company’s long-term debt in years 2009 or 2011.

 

Future Capital Requirements

 

Capital Expenditures

 

The Company’s current 2007 to 2012 construction program includes continued investment in OG&E’s distribution, generation and transmission system and Enogex’s pipeline assets. The Company’s current estimates of capital expenditures for 2007 through 2012 are approximately $568.1 million, $838.6 million, $815.9 million, $659.9 million, $550.2 million and $436.0 million, respectively, which include capital expenditures of approximately $94.0 million, $278.8 million, $285.7 million, $97.7 million and $34.1 million, respectively, in 2007 through 2011 related to the construction of the Red Rock power plant. OG&E also has approximately 550 MW’s of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

 

Pension and Postretirement Benefit Plans

 

During 2006, actual asset returns for the Company’s defined benefit pension plan were positively affected by growth in the equity markets. At December 31, 2006, approximately 64 percent of the pension plan assets are invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2006, asset returns on the pension plan were approximately 14.5 percent as compared to approximately 6.2 percent in 2005. During the same time,

 

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corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.

 

Contributions to the pension plan increased from approximately $32.0 million in 2005 to approximately $90.0 million in 2006. This increase in pension plan contributions in 2006 was to maintain an adequate funded status. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2007, the Company may contribute up to $50 million to its pension plan.

 

In accordance with Statement of Financial Accounting Standard (“SFAS”) No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2006, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement in 2006. As a result, the Company recorded a pension settlement charge for 2006 of approximately $17.1 million in the fourth quarter of 2006. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense over time, as the charge was an acceleration of costs that otherwise would have been recognized as pension expense in future periods. OG&E’s Oklahoma jurisdictional portion of this charge was recorded as a regulatory asset (see Note 1 of Notes to Consolidated Financial Statements for a further discussion).

 

As discussed in Note 15 of Notes to Consolidated Financial Statements, in 2000 the Company made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired after January 31, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, the Company’s cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, the Company’s cash requirements should decrease and will be much less sensitive to changes in discount rates.

 

At December 31, 2006, the projected benefit obligation and fair value of assets of the Company’s pension plan and restoration of retirement income plan was approximately $585.0 million and $519.4 million, respectively, for an underfunded status of approximately $65.6 million. Also, at December 31, 2006, the accumulated postretirement benefit obligation and fair value of assets of the Company’s postretirement benefit plans was approximately $225.4 million and $74.0 million, respectively, for an underfunded status of approximately $151.4 million. The above amounts have been recorded in Accrued Pension and Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E’s portion which is recorded as a regulatory asset as discussed in Note 1 of Notes to Consolidated Financial Statements) in the Company’s Consolidated Balance Sheet. The entry did not impact the results of operations in 2006 and did not require a usage of cash and is therefore excluded from the Consolidated Statement of Cash Flows. The amounts in Accumulated Other Comprehensive Loss and as a regulatory asset represent a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.

 

During 2005, the Company made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a net prepaid benefit obligation at December 31, 2005 of approximately $88.9 million. At December 31, 2005, the Company’s projected pension benefit obligation exceeded the fair value of the pension plan assets by approximately $154.6 million. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87 required the recognition of an additional minimum liability in the amount of approximately $181.4 million at December 31, 2005. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2005 and did not require a usage of cash and is therefore excluded from the Consolidated Statement of Cash Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other Comprehensive Income represents a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.

 

Pension Plan Costs and Assumptions

 

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it

 

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introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants. The Company is currently analyzing the impact of the Pension Protection Act on its pension plans.

 

Long-Term Debt with Optional Redemption Provisions

 

OG&E’s $125.0 million principal amount 6.65 percent Senior Notes (“Senior Notes”) due July 15, 2027, are repayable on July 15, 2007, at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to July 15, 2007. Only holders who submit requests for repayment between May 15, 2007 and June 15, 2007 are entitled to such repayments. In accordance with SFAS No. 6, “Classification of Short-Term Obligations Expected to Be Refinanced,” OG&E reclassified the Senior Notes from long-term debt due within one year to long-term debt at December 31, 2006 due to OG&E having sufficient long-term liquidity in place as a result of increasing its revolving credit agreement to $400.0 million in December 2006. Also, based on where the Senior Notes have recently traded, OG&E does not believe it is probable that this option will be exercised by the note holders.

 

SPP Letter of Credit

 

On October 31, 2006, OG&E submitted a commercial letter of credit to the Southwest Power Pool for approximately $2.9 million related to the costs of upgrades required for OG&E to obtain transmission service from its new Centennial wind farm. This commercial letter of credit is not recorded as a liability on the Company’s Consolidated Balance Sheet.

 

Security Ratings

                

 

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

 

Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

 

Future Sources of Financing

 

Management expects that internally generated funds, the issuance of long and short-term debt and proceeds from the sales of common stock to the public through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

 

Short-Term Debt

 

Short-term borrowings generally are used to meet working capital requirements. In December 2006, the Company and OG&E increased their aggregate available borrowing capacity under their revolving credit agreements from $750.0 million to $1.0 billion, $600 million for the Company and $400 million for OG&E. Also, OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2007 and ending December 31, 2008. See Note 14 of Notes to Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

 

Common Stock

 

See Note 11 of Notes to Consolidated Financial Statements for a discussion of the Company’s common stock activity.

 

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Critical Accounting Policies and Estimates

 

The Consolidated Financial Statements and Notes to Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material affect on the Company’s Consolidated Financial Statements particularly as they relate to pension expense and impairment estimates. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s Audit Committee.

 

Consolidated (including Electric Utility and Natural Gas Pipeline Segments)

 

Pension and Postretirement Benefit Plans

 

Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 15 of Notes to Consolidated Financial Statements. The assumed return on plan assets is based on management’s expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the pension plan. The following table indicates the sensitivity of the pension plan funded status to these variables.

 

 

Impairment of Assets

 

The Company assesses potential impairments of assets or asset groups when there is evidence that events or changes in circumstances require an analysis of the recoverability of an asset or asset group. For purposes of recognition and measurement of an impairment loss, a long-lived asset or assets shall be grouped with other assets and liabilities at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future cash flows used to test the recoverability of a long-lived asset or asset group shall include only the future cash flows (cash inflows less associated cash outflows) that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the asset or asset group. The fair value of these assets is based on third-party evaluations, prices for similar assets, historical data and projected cash flow. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset. Enogex expects to continue to evaluate the strategic fit and financial performance of each of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been included in the 2007 earnings guidance.

 

Commitments and Contingencies

 

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various

 

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regulatory agencies and income tax related items. Management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Consolidated Financial Statements.

 

Asset Retirement Obligations

 

In accordance with FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” an entity was required to recognize a liability for the fair value of an asset retirement obligation (“ARO”) that was conditional on a future event if the liability’s fair value could be reasonably estimated. The fair value of a liability for the conditional ARO was recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO was factored into the measurement of the liability when sufficient information existed. However, in some cases, there was insufficient information to estimate the fair value of an ARO. In these cases, the liability was initially recognized in the period in which sufficient information was available for an entity to make a reasonable estimate of the liability’s fair value. In the fourth quarter of 2006, OG&E recorded an ARO for approximately $0.9 million related to its Centennial wind farm. Beginning January 1, 2007, the Company will amortize the remaining value of the related ARO asset over the estimated remaining life of 99 years. The Company has also identified other ARO’s that have not been recorded because the Company determined that these assets have indefinite lives primarily related to Enogex’s processing plants and compression sites.

 

Hedging Policies

 

Enogex engages in cash flow hedge transactions to manage commodity risk. Enogex may hedge its forward exposure to manage changes in commodity prices. Anticipated transactions are documented as cash flow hedges pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” hedging requirements and are executed based upon management established price targets.  During 2004 and 2005, Enogex and OERI utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas and certain types of natural gas liquid hedges. During 2006, Enogex and OERI utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas, natural gas liquid hedges and certain transportation hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. OG&E and Enogex engage in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2004, OG&E and Enogex entered into interest rate swap agreements and, during 2005 and 2006, OG&E entered into treasury lock agreements relating to managing interest rate exposure on the debt portfolio or anticipated debt issuances to modify the interest rate exposure on fixed rate debt issues.  These interest rate swaps and treasury lock agreements qualified as fair value or cash flow hedges under SFAS No. 133. The objective of the interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. The objective of the treasury lock agreements in late 2005 was to protect against the variability of future payments of interest expense of debt that was issued by OG&E in January 2006 and the objective of the treasury lock agreement in November 2006 is to protect against the variability of future interest payments of long-term debt that is expected to be issued during the first half of 2007.

 

Electric Utility Segment

 

Regulatory Assets and Liabilities

 

OG&E, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

 

OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The Company adopted certain provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which requires the Company to separately disclose the items that have not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required this information to be included in

 

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Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, this information is allowed to be recorded as a regulatory asset if: (i) the utility has historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there is no negative evidence that the existing regulatory treatment will change. Therefore, OG&E has recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicated a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

 

Unbilled Revenues

 

OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. At December 31, 2006, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of approximately $0.2 million. At December 31, 2006 and 2005, Accrued Unbilled Revenues were approximately $39.7 million and $41.8 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

 

Allowance for Uncollectible Accounts Receivable

 

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. At December 31, 2006, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of approximately $0.3 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable, Net on the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was approximately $3.3 million and $2.5 million at December 31, 2006 and 2005, respectively.

 

Natural Gas Pipeline Segment

 

Operating Revenues

 

Operating revenues for transportation, storage, gathering and processing services for Enogex are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current month nominations and contracted prices. Operating revenues associated with the production of natural gas liquids are estimated based on current month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable, Net on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.

 

Natural Gas Purchases

 

Estimates for gas purchases are based on sales volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

 

Energy Purchase and Sale Contracts

 

OERI’s activities include the marketing of natural gas and natural gas liquids. The vast majority of these contracts expire within three years, which is when the cash aspect of the transactions will be realized. A substantial portion of these contracts qualify as derivatives under SFAS No. 133 and are marked-to-market with offsetting gains and losses recorded in earnings. In nearly all cases, independent market prices are obtained and compared to the values used for this mark-to-market valuation, and an oversight group outside of the marketing organization monitors all modeling methodologies and assumptions.   The recorded value of the energy contracts may change significantly in the future as the market price for the commodity changes, but the value is still subject to the risk loss limitations provided under the Company’s risk policies. The

 

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Company utilizes models to estimate the fair value of its energy contracts including derivatives that do not have an independent market price. At December 31, 2006, unrealized mark-to-market gains were approximately $31.2 million, which included approximately $0.5 million of unrealized mark-to-market gains that were calculated utilizing models. At December 31, 2006, a price movement of one percent for prices verified by independent parties would result in changes in unrealized mark-to-market gains of less than $0.1 million and a price movement of five percent on model-based prices would result in changes in unrealized mark-to-market gains of approximately $0.1 million. Energy contracts are presented in Price Risk Management assets, liabilities or against the brokerage deposits in Other Current Assets on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.

 

Natural Gas Inventory

 

Natural gas inventory is held by Enogex Inc. and OERI. Enogex Inc. maintains of natural gas inventory to provide operational support for its pipeline deliveries. As part of its recurring business activity, OERI injects and withdraws natural gas in to and out of inventory under the terms of its storage capacity contracts. In order to mitigate market price exposures, OERI enters into contracts or hedging instruments to protect the cash flows associated with its inventory. OERI has elected not to designate inventory hedging contracts as fair value or cash flow hedges under SFAS No. 133. The fair value of the hedging instruments is recorded on the books of OERI as Price Risk Management assets, liabilities or against the brokerage deposits in Other Current Assets with an offsetting gain or loss recorded in current earnings. All natural gas inventory held by Enogex is recorded at the lower of cost or market. During 2006, Enogex recorded write-downs to market value related to natural gas storage inventory of approximately $18.7 million. The amount of Enogex’s natural gas inventory was approximately $35.9 million and $35.7 million at December 31, 2006 and 2005, respectively.  Natural gas storage inventory is presented in Fuel Inventories on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

 

Allowance for Uncollectible Accounts Receivable

 

The allowance for uncollectible accounts receivable is calculated based on outstanding accounts receivable balances over 180 days old. In addition, other outstanding accounts receivable balances less than 180 days old are reserved on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable, Net on the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable for the Natural Gas Pipeline segment was approximately $1.1 million and $1.2 million at December 31, 2006 and 2005, respectively.

 

Accounting Pronouncements

 

See Notes 2 and 3 of Notes to Consolidated Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

 

Electric Competition; Regulation

 

OG&E and Enogex have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on the Company due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring also could have a significant impact on the Company’s consolidated financial position, results of operations and cash flows. The Company cannot predict when it will be subject to changes in legislation or regulation, nor can it predict the impact of these changes on the Company’s consolidated financial position, results of operations or cash flows. The Company believes that the prices for electricity and the quality and reliability of the Company’s service currently place us in a position to compete effectively in the energy market. These developments at the federal and state levels are described in more detail in Note 18 of Notes to Consolidated Financial Statements. OG&E is also subject to competition in various degrees from state-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. OG&E has a franchise to serve in more than 270 towns and cities throughout its service territory. In a citywide election in May 2006, Oklahoma City voters approved a 25-year franchise for OG&E which is the largest city in OG&E’s service territory.

 

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Commitments and Contingencies

 

Except as disclosed otherwise in this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. See Notes 17 and 18 of Notes to Consolidated Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of the Company’s commitments and contingencies.

 

Quantitative and Qualitative Disclosures About Market Risk.

 

Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in commodity prices, commodity price volatilities and interest rates. The Company is exposed to commodity price and commodity price volatility risks in its operations. The Company’s exposure to changes in interest rates relates primarily to short-term variable-rate debt, interest rate swap agreements, treasury lock agreements and commercial paper. The Company also engages in price risk management activities for both trading and non-trading purposes.

 

Risk Committees and Oversight

 

The Company monitors market risks using a risk committee structure. The Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all risk management activities of the Company. This committee’s emphasis is a holistic perspective of risk measurement and policies targeting the Company’s overall financial performance. The Risk Oversight Committee is authorized by, and reports quarterly to, the Audit Committee of the Board of Directors.

 

The Unregulated Business Unit Risk Management Committee is comprised primarily of business unit leaders within Enogex. This committee’s purpose is to develop and maintain risk policies for Enogex, to provide oversight and guidance for existing and prospective Enogex business activities and to provide governance regarding compliance with Enogex risk policies. This group is authorized by and reports to the Risk Oversight Committee.

 

The Company also has a Corporate Risk Management Department led by our Chief Risk and Compliance Officer. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the Company’s risk policies.

 

Risk Policies

 

The Company utilizes risk policies to control the amount of market risk exposure. These policies, which include value-at-risk (“VaR”) limits, position limits, tenor limits and stop loss limits, are designed to provide the Audit Committee of the Board of Directors and senior executives of the Company with confidence that the risks taken on by the Company’s business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to risk management are being followed.

 

Interest Rate Risk

 

The Company’s exposure to changes in interest rates relates primarily to short-term debt, interest rate swap agreements, treasury lock agreements and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

 

Cash Flow Hedge of Interest Rates

 

OG&E entered into a treasury lock agreement, effective November 17, 2006, to hedge interest payments on the first $50.0 million of long-term debt that is expected to be issued during the first half of 2007. This treasury lock expires March 29, 2007.

 

The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities. At December 31, 2006, the Company had no outstanding

 

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interest rate swap agreements. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.

 

(A) Prior to or when these debt obligations mature, the Company may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

(B) A hypothetical change of 100 basis points in the underlying variable interest rate would change interest expense by approximately $1.4 million annually.

 

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The Company’s price risk management assets and liabilities as of December 31, 2006 were as follows: