2004 Proxy

OGE Energy Corp.

PO Box 321
Oklahoma City, Oklahoma 73101-0321
405-553-3000
www.oge.com

OG&E

March 31, 2005

Securities and Exchange Commission
Division of Corporation Finance
450 Fifth Street, N.W.
Washington, D.C. 20549

Gentlemen:

On behalf of OGE Energy Corp., enclosed for electronic filing, pursuant to Rule 14a-6(b), is a definitive copy of the proxy solicitation material relating to the Annual Meeting of Shareowners of the Company to be held on May 19, 2005.

Please note that copies of the proxy solicitation material are this day being sent to the New York and Pacific Stock Exchanges in accordance with Rule 14a-6(b).

The Company intends to commence mailing the foregoing material to its shareowners on approximately March 31, 2005, and to complete the same as soon as possible.

	Sincerely,


	/s/ Carla D. Brockman
	Carla D. Brockman
	Corporate Secretary

Enclosure

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:

OGE Energy Corp.

Proxy Statement
and
Notice of Annual Meeting

May 19, 2005

OG+E

	Page

Chairman’s Letter	1	Notice of Annual Meeting
		of Shareowners
Notice of Annual Meeting of Shareowners	2	and Proxy Statement

Proxy Statement	3
		Thursday, May 19, 2005, at 10:00 a.m.
Proposal No. 1 - Election of Directors	4
		National Cowboy and Western Heritage Museum
Proposal No. 2 - Ratification of Ernst &	12	1700 Northeast 63rd Street
Young LLP as Company’s Principal		Oklahoma City, Oklahoma
Independent Accountants

Report of Audit Committee	13

Executive Officers’ Compensation	15

Report of Compensation	15
Committee on Executive
Compensation

Summary Compensation Table	19

Pension Plan Table	21

Employment Agreements and	23
Change of Control Arrangements

Company Stock Performance	24

Security Ownership	25

Equity Compensation Plan Information	26

Section 16(a) Beneficial	26
Ownership Reporting Compliance

Shareowner Proposals	26

Householding Information	27

Map	27

Annex A - Audit Committee Charter	A-1

Appendix A - 2004 Financial Statements
and Management’s Discussion and Analysis

OGE Energy Corp.

March 31, 2005

Dear Shareowner:

You are cordially invited to attend the annual meeting of OGE Energy Corp. at 10:00 a.m. on Thursday, May 19, 2005, 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.

	Very truly yours,


	/s/ Steven E. Moore
	Steven E. Moore
	Chairman of the Board, President
	and Chief Executive Officer

Notice of Annual Meeting
of Shareowners

The Annual Meeting of Shareowners of OGE Energy Corp. will be held on Thursday, May 19, 2005, at 10:00 a.m. at the National Cowboy and Western Heritage Museum, 1700 Northeast 63rd Street, Oklahoma City, Oklahoma, for the following purposes:

(1) To elect three directors to serve for a three-year term;

(2) To ratify the appointment of Ernst & Young LLP as our principal independent accountants; and

(3) To transact such other business as may properly come before the meeting.

The map on page 27 will assist you in locating the National Cowboy and Western Heritage Museum.

Shareowners who owned stock on March 21, 2005, 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.




	/s/ Carla D. Brockman
	Carla D. Brockman
	Corporate Secretary

Dated: March 31, 2005

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.

Proxy Statement

March 31, 2005

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 19, 2005, at 10:00 a.m. For the convenience of those shareowners who may attend the meeting, a map is printed on page 27 that gives directions to the National Cowboy and Western Heritage Museum. At the meeting, it is intended that the first two items in the accompanying notice will be presented 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, William E. Durrett and Robert Kelley as your representatives at the Annual Meeting. Mr. Moore, Mr. Durrett 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. Durrett 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 three 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 Dividend Reinvestment and Stock Purchase Plan (“DRIP”) 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, 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 21, 2005, you are entitled to one vote per share upon each matter presented at the meeting.

On March 1, 2005, there were 89,979,541 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.

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 31, 2005. 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 31, 2005, to all of our shareowners who owned stock on March 21, 2005.

Voting Under Plans

If you are a participant in our DRIP, your proxy will represent the shares held on your behalf under the DRIP 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 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 three persons are the nominees of the Board to be elected for such three-year term at the Annual Meeting to be held on May 19, 2005: Mr. Herbert H. Champlin, Mrs. Linda Petree Lambert and Dr. Ronald H. White, M.D. Each of these individuals is currently a director of the Company whose term as a director is scheduled to expire at the Annual Meeting.

Mrs. Martha W. Griffin will retire from the Board effective at the Annual Meeting. Mrs. Griffin has served as a director of the Company’s principal subsidiary, Oklahoma Gas and Electric Company (“OG&E”), since 1987 and as a director of OGE Energy since its inception in 1996. The Board of Directors expresses its sincere appreciation and thanks to Mrs. Griffin for her many years of contribution and dedicated service.

The enclosed proxy, unless otherwise specified, will be voted in favor of the election as directors of the previously listed three 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 .96% 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.

Each director of the Company during 2004 was also a director of Oklahoma Gas and Electric Company (“OG&E”). The Company became the parent company of OG&E pursuant to a corporate reorganization, effective December 31,1996.

INFORMATION ABOUT DIRECTORS AND NOMINEES

The following contains certain information as of March 1, 2005, concerning the three nominees for directors, as well as the directors whose terms of office extend beyond the Annual Meeting on May 19, 2005.

*Nominees for Election for Term Expiring at 2008 Annual Meeting of Shareowners*

HERBERT H. CHAMPLIN, 67, is President of Champlin Explorations, Inc., an independent oil producer, and Chairman of Enid Data Systems, computer marketers, both located in Enid, Oklahoma. Mr. Champlin also was engaged separately during 2004 as a part of his principal business occupation in the petroleum industry and had interests in oil and gas wells. Mr. Champlin has been a director of the Company since December 31, 1996, and of OG&E since 1982, and is a member of the audit and compensation committees of the Board.	Photo

LINDA PETREE LAMBERT, 65, is President of Lasso Corporation, a diversified oil and gas investment company, president of Enertree, L.L.C., also an oil and gas investment company, and a partner in Petree Valley Farms, a working farm in Verden, Oklahoma. Ms. Lambert also serves as a member of the Board of Directors of InvesTrust, a privately held trust company, the Oklahoma National Memorial Foundation and the United Way of Oklahoma City. Ms. Lambert has been a director of the Company and of OG&E since November 2004, and is a member of the nominating and corporate governance committee of the Board.

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RONALD H. WHITE, M.D., 68, is a practicing cardiologist and President, Partner and Director of Oklahoma Cardiovascular Associates, and a member of the Board of Managers of Oklahoma Heart Hospital. He was a member of the Board of Regents of the University of Oklahoma for 14 years. Presently Dr. White is a member of the Oklahoma State Regents for Higher Education. Dr. White has been a director of the Company since December 31, 1996, and of OG&E since 1989, and is a member of the compensation committee and the nominating and corporate governance committee of the Board.

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Directors Whose Terms Expire at 2007 Annual Meeting of Shareowners

LUKE R. CORBETT, 58, is Chairman and Chief Executive Officer of Kerr-McGee Corporation, which is engaged in oil and gas exploration and production and chemical operations. He has been employed by Kerr-McGee Corporation for more than 17 years, having served as Chairman and Chief Executive Officer since 1997; President and Chief Operating Officer from 1995 to 1997; and Group Vice President from 1992 to 1995. Mr. Corbett also serves as a member of the Board of Directors of Noble Corporation and of BOK Financial Corporation. Mr. Corbett will not be standing for reelection to the Board of BOK Financial Corporation and his term as a director of that corporation is expected to expire on April 26, 2005. Mr. Corbett has been a director of the Company since December 31, 1996, and of OG&E since December 1, 1996, and is chairman of the compensation committee and is a member of the audit committee of the Board.

Photo

ROBERT KELLEY, 59, is President of Kellco Investments Inc., a private investment company. Prior to May 1, 2001, he served as Chairman of the Board of Noble Affiliates, Inc., an independent energy company with exploration and production operations in the United States and international operations in China, Equador, Equatorial Guinea and the U.K. sector of the North Sea. Prior to October 2, 2000 he also served as President and Chief Executive Officer of Noble Affiliates, Inc. and of its three subsidiaries: Samedan Oil Corporation, Noble Gas Marketing, Inc. and Noble Trading, Inc. Mr. Kelley also serves as a member of the Board of Directors and audit committee of Lone Star Technologies, Inc., Cabot Oil and Gas Corporation and Seitel, Inc. The Board of Directors of the Company has determined that Mr. Kelley’s service on these other audit committees does not impair his ability to effectively serve on the Company’s audit committee. Mr. Kelley is a certified public accountant and his prior experiences include working for a public accounting firm and teaching accounting at two universities. Mr. Kelley has been a director of the Company since December 31, 1996, and of OG&E since January 17, 1996, and is chairman of the audit committee and is a member of the compensation committee of the Board.

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J. D. WILLIAMS, 67, is founder and a former member of Williams & Jensen, P.C., a law firm in Washington, D. C., having resigned as a member of the firm in 1991. He remained an employee of the firm until his retirement in December 2004 and has agreed to make himself available as an independent contractor to provide limited services to the firm through December 31, 2007. During 2004, the Company paid Williams & Jensen less than $500,000 (which was less than 5% of the firm’s annual revenues) for various legal services and expects to retain Williams & Jensen to provide similar services in 2005. Mr. Williams is involved in various civic and related matters and also serves as a member of the Board of Directors of Seitel, Inc. Mr. Williams has been a director of the Company and of OG&E since January 2001, and is chairman of the nominating and corporate governance committee of the Board.

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Directors Whose Terms Expire at 2006 Annual Meeting of Shareowners

WILLIAM E. DURRETT, 74, is Senior Chairman of the Board of American Fidelity Corporation, an insurance holding company and Chairman of North American Insurance Agency, Inc. From May 1998 to October 1999, he served as President and Chief Executive Officer of North American Insurance Agency, Inc. Mr. Durrett served as President and Chief Executive Officer of American Fidelity Corporation from 1978 to 1998 and as Chairman of American Fidelity Corporation from 1989 to 1998. He also serves as a member of the Boards and holds various executive positions in numerous other subsidiaries of American Fidelity Corporation. He serves as a director of BOK Financial Corporation and INTEGRIS Health. Mr. Durrett has been a director of the Company since December 31, 1996, and of OG&E since March 1991, and is a member of the audit committee and the nominating and corporate governance committee of the Board.

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JOHN D. GROENDYKE, 60, is Chairman of the Board and Chief Executive Officer of Groendyke Transport Incorporated, a bulk truck transportation company in Enid, Oklahoma. Mr. Groendyke has worked at Groendyke Transport, Inc. since 1965. Mr. Groendyke is also Chairman of the Board and President of Bell Transport, Inc.; Oringderrf Tank Line, Inc.; Transport Company, Inc.; and Triple “A” Transport and is Chairman of the Board of GTI Insurance Co. Inc. and of James, Inc. Mr. Groendyke also serves as Director of Central Service Corp. and Central National Bank. Mr. Groendyke has been a director of the Company and of OG&E since January 2003 and is a member of the compensation committee and the nominating and corporate governance committee of the Board.

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STEVEN E. MOORE, 58, is Chairman, President and Chief Executive Officer of the Company and of OG&E, having been appointed to such positions with the Company effective December 31, 1996. Mr. Moore was appointed President of OG&E in August 1995, and as Chief Executive Officer and Chairman of OG&E in May 1996. Mr. Moore has been employed by OG&E for more than 30 years, having previously served as Senior Vice President of Law and Public Affairs. He also serves as a director of BOK Financial Corporation, INTEGRIS Health, and has served on many industry-wide committees in the electric utility industry. Mr. Moore has been a director of the Company since 1996 and of OG&E since October 1995.

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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 election of the three nominees as director. Withholding authority is treated as a vote against.

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

INFORMATION CONCERNING THE BOARD OF DIRECTORS

Each member of our Board of Directors was also a director of OG&E during 2004. The Board of Directors of the Company met on six occasions during 2004 and the Board of Directors of OG&E met on six occasions during 2004. Each director attended at least 88% 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.

All members of these committees are independent, as independence is defined in the listing standards of the New York Stock Exchange. In addition, the Board has determined that Mr. Robert Kelley meets the Securities and Exchange Commission (“SEC”) definition of audit committee financial expert.

The members of the committees during 2004, the general functions of the committees and number of committee meetings in 2004 are set forth below.

Name of Committee	General Functions	Number of
and Members	of the Committee ***	Meetings in 2004

Compensation Committee:	Oversees	5
Herbert H. Champlin	o compensation of directors and principal officers
Luke R. Corbett*	o executive compensation policy
Martha W. Griffin	o benefit programs
John D. Groendyke
Robert Kelley
Ronald H. White, M.D.

Audit Committee:	Oversees financial reporting process	6
Herbert H. Champlin	o evaluate performance of independent auditors
Luke R. Corbett	o select independent auditors
William E. Durrett	o discuss with internal and independent auditors
Robert Kelley*	scope and plans for audits, adequacy and
J.D. Williams**	effectiveness of internal controls for financial
	reporting purposes, and results of their
	examinations
	o review interim financial statements and annual
	financial statements to be included in Form 10-K

Nominating and Corporate	Reviews and recommends	5
Governance Committee:	o nominees for election as directors
William E. Durrett	o membership of director committees
Martha W. Griffin	o succession plans
John D. Groendyke	o various corporate governance issues
Linda Petree Lambert
Ronald H. White, M.D.
J.D. Williams*
* Chairperson
** Mr. Williams ceased being a member of the Audit Committee on November 17, 2004.
*** The specific duties for each committee are set forth in the charter of the committee, which, in the case of the audit committee, is attached as Annex A, and, in the case of the compensation committee and the nominating and corporate governance committee, is available on the OGE Energy web site at www.oge.com under the heading Investors, Corporate Governance.

Corporate Governance

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 should be the only Company executive 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 chief executive officer, 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 chief executive officer 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 in 2004.

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 are to meet in executive session, generally coinciding with regularly scheduled Board meetings. In 2004, the independent directors met in executive session five 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 chief executive officer 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 new 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 is composed of ten directors, nine of whom are independent within the meaning of the New York Stock Exchange listing standards. Our Chairman and Chief Executive Officer is the only member of management serving as a director. 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:

o	A director who is or was an employee, or whose immediate family member is or was an executive officer of the Company or any of our subsidiaries is not independent until three years after the end of such employment relationship;

A director who received, or whose immediate family member received, more than $100,000 during any twelve-month period within the past three years in direct compensation from us or any of our subsidiaries, other than director and committee fees and pension or other forms or deferred compensation for prior 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;

o	A director who is a current partner or employee, or whose immediate family member is a current partner, of a firm that is the internal or external auditor of the Company or any of our subsidiaries is not independent;

A director who was, or whose immediate family member was, within the last three years (but is no longer) a partner or employee of the internal or external auditor of the Company or any of our subsidiaries and who personally worked on the audit of the Company or any of its subsidiaries within that time is not independent;

o	A director whose immediate family member is a current employee of the internal or external auditor of the Company or any of our subsidiaries and who participates in the firm’s audit, assurance or tax compliance (but not tax planning) practice is not independent;

A director who is or was employed, or whose immediate family member is or was employed, as an executive officer of another company where, at the same time, any of our or any of our subsidiaries’ present executives is or was serving on that company’s compensation committee is not independent until three years after the end of such service or the employment relationship;

A director who is a current employee, or whose immediate family member is a current executive officer, of a company that makes payments to, or receives payments from, us or any of our subsidiaries for property or services in an amount which, in any of the past three fiscal years, exceeds the greater of $1 million, or 2% of such other company’s consolidated gross revenues, is not independent until three years after falling below such threshold; and

No director qualifies as independent unless the Board affirmatively determines that the director has no other relationship with us or any of our subsidiaries (either directly or as a partner, shareholder or officer of an organization that has a relationship with us or any of our subsidiaries) that in the opinion of the Board of Directors could be considered to affect the directors ability to exercise his or her independent judgement as a director.

The Board determined that each of the following members of the Board, met the aforementioned independence standards: Herbert H. Champlin; Luke R. Corbett; William E. Durrett; Martha W. Griffin; John D. Groendyke; Robert Kelley; Linda Petree Lambert; Ronald H. White, M.D. and J.D. Williams. Mr. Moore does not meet the aforementioned independence standards, because he is the current Chief Executive Officer and an employee of the Company.

Standing Committees. Our Board has three standing committees — 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. The duties and responsibilities of the Board committees are reviewed regularly and are outlined above.

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 five times in 2004.

Communications with the Board of Directors. Shareowners 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 nine of the Board members serving at the time attended the Annual Meeting in 2004.

Prohibition on Loans. During 2004, the Company amended its Stock Incentive Plan to make it absolutely clear that all loans to executive officers are prohibited.

Auditors; Audit Partner Rotation. As described on page 12 below, the Company is requesting that the shareowners ratify the selection of Ernst & Young LLP as the Company’s principal accountants for 2005. During 2004, the Audit Committee charter was amended to make it absolutely clear 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 17 in the Report of the Compensation Committee on Executive Compensation.

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 not 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. In 2004, the committee did not use any third party advisors to assist in the identification of potential candidates, but instead relied on an internal list compiled from recommendations of the committee and other members of the board.

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, 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 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.

Following that process, in November 2004, the committee selected Ms. Linda Petree Lambert as the candidate that best suited our needs and recommended to the Board that she be elected as a director. Ms. Lambert’s election was approved by the Board for a term expiring at this Annual Meeting.

Director Compensation. Compensation of non-officer directors of the Company during 2004 consisted of an annual retainer fee of $66,000, of which $2,000 was payable monthly in cash (the same amount that has been paid monthly since August 1994) and $42,000 was deposited in the director’s account under the Directors’ Deferred Compensation Plan and converted to 1,624.758 common stock units based on the closing price of the Company’s Common Stock on November 30, 2004. The chairmen of the audit, compensation and nominating and corporate governance committees received an additional $5,000 annual cash retainer in 2004. In addition, all non-officer directors received $1,000 for each Board meeting and $1,000 for each committee meeting attended. These amounts represent the total fees paid to directors in their capacities as directors of the Company and OG&E. For 2005, the fee for attendance at a Board or committee meeting was increased to $1,200. Also, the fee for acting as lead director was set at $10,000, the additional annual retainer for acting as chairman of the audit committee was increased to $10,000, and the additional annual retainer for acting as chairman of the compensation committee and the nominating and corporate governance committee remained at $5,000, with each of these additional amounts payable in November 2005.

Under the Directors’ Deferred Compensation Plan (the “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 on the date 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 Plan. During 2004, 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 Plan are paid in cash in a lump sum or installments.

Historically, for those directors who retired from the Board of Directors after 10 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.

PROPOSAL NO. 2
RATIFICATION OF THE APPOINTMENT OF ERNST & YOUNG LLP AS THE
COMPANY’S PRINCIPAL INDEPENDENT ACCOUNTANTS FOR 2005

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, 2005. 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 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 2005. 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.

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 four 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. A copy of the Audit Committee charter is attached as Annex A. 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 2004 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 2004 financial statements and management’s assessment of the Company’s internal controls 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 controls 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. 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 2005. 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 six meetings during 2004 and the Chairman of the Audit Committee met with the auditors by telephone on a quarterly basis to discuss the Company’s quarterly financial statements.

Fees for Independent Auditors

Audit Fees

Total audit fees for 2004 were $1,942,965 for the Company’s 2004 financial statement audit. These fees include $923,125 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $66,614 for services in support of debt and stock offerings. Total audit fees for 2003 were $789,326, which includes $140,755 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 2004, this amount includes estimated billings for the completion of the 2004 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, 2004 were $103,870, of which $61,500 was for employee benefit plan audits and $42,370 for other audit-related services.

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2003 were $91,550. These fees include $56,000 for employee benefit audits and $35,550 for other audit-related services.

Tax Fees

The aggregate fees billed for tax services for the fiscal year ended December 31, 2004 were $840,995. These fees include $176,207 for tax preparation and compliance ($74,882 for the review of federal and state tax returns and $101,325 for assistance with examinations and other return issues), $418,000 for tax assis-

tance with the Oklahoma Investment Tax Credits, meals and entertainment project, Oklahoma sales and use tax, $181,248 for a change in our tax accounting method and $65,540 for other tax services.

The aggregate fees billed for tax services for the fiscal year ended December 31, 2003 were $1,028,594. These fees include $174,338 for tax preparation and compliance ($53,490 for the review of federal and state tax returns and $120,848 for assistance with examinations and other return issues), $478,206 for a change in our tax accounting method, $338,742 for assistance with the Oklahoma Investment Tax Credits and $37,308 for other tax services.

All Other Fees

There were no other fees billed to the Company in 2004 or 2003 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, 2004, for filing with the Securities and Exchange Commission. The Audit Committee selected Ernst & Young LLP as the Company’s independent public accountants for 2005. Representatives of Ernst & Young LLP will be present at the Annual Meeting of Shareowners and will have the opportunity to make a statement if they so desire. Such representatives will be available to respond to appropriate questions from shareowners at the meeting.

Audit Committee Pre-Approval Procedures

Rules adopted by the Securities and Exchange Commission 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 2004, 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
William E. Durrett, member
J.D. Williams*, member

* Mr. Williams served on the Audit Committee through November 17, 2004. He joins in the report of the Audit Committee to the extent it covers the period for which he served on the Committee during 2004.

EXECUTIVE OFFICERS’ COMPENSATION

The Compensation Committee of the Board of Directors of the Company (the “Committee”) administers our executive compensation program. The Committee’s report on compensation paid to executive officers during 2004 is set forth below.

REPORT OF COMPENSATION COMMITTEE ON EXECUTIVE COMPENSATION

General. The primary goals of the Committee in setting executive compensation in 2004 were: (i) to provide a competitive compensation package that would enable us to attract and retain key executives and (ii) to align the interests of our executives with those of our shareowners and also with our performance.

Compensation to our executive officers in 2004 was comprised primarily of salary, annual awards under our Annual Incentive Compensation Plan and long-term awards under our Stock Incentive Plan. In an effort to ensure the continued competitiveness of our executive compensation policies, the Committee 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, the Committee considered the compensation paid at the 50th percentile to executives with similar duties within the following three groups: (i) the 2003 Energy Services Industry Executive Compensation Database (the “Energy Services Survey Group”), consisting of approximately 88 electric services organizations, (ii) the 2003 General Industry Executive Compensation Database (the “General Industry Survey Group”), consisting of more than 739 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”).1 All compensation data from these surveys was size-adjusted so that it would compare to the Company’s or a subsidiary’s revenues, as appropriate, and was updated using a 3.75 percent update factor to reflect anticipated 2004 compensation levels.

The Committee’s intent in setting salaries is to pay competitive rates. The annual and long-term incentive portions of an executive’s compensation are intended to achieve the Committee’s goal of aligning an executive’s interests with our shareowners’ and with our performance. These portions of an executive’s compensation are placed at risk and are linked to the accomplishment of specific results that are designed to benefit our shareowners and the Company, both in the long and short term. As a result, during years of excellent performance, executives are provided the opportunity to earn a highly competitive level of compensation and, conversely, in years of below-average performance, their compensation may be below competitive levels. Generally, higher level executive officers have a greater level of their compensation placed at risk.

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.

Base Salary. The base salaries for our executive officers in 2004 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 serving only at our utility subsidiary, OG&E. Base salaries of our executive officers generally approximated the salary at the 50th percentile of the range for executives with similar duties in the appropriate survey group. Actual base salaries were determined based on individual performance and experience. The salaries of executive officers for 2004 were determined in November 2003, with an effective date of January 1, 2004. Salaries were subject to adjustment during the year if an individual’s duties and responsibilities changed. The 2004 base salary amounts for the most highly compensated executive officers are shown in the salary column of the Summary Compensation Table on page 19 and, for three of the six individuals listed, remained unchanged from their 2003 base salary amounts.

Annual Incentive Compensation Plan. Awards with respect to 2004 performance were made under the An-

The companies in the Energy Services Survey Group, General Industry Survey Group and Blended Industry Survey Group are not the same as the companies in the S&P 500 Electric Utilities Index utilized in the Stock Performance Graph on page 24. The survey groups were selected by Towers Perrin, the Committee’s compensation consultants, and, in the judgment of the Committee, are appropriate peer groups to consider for compensation purposes.

nual Incentive Compensation Plan to 86 employees, including all executive officers. The Plan was designed to provide key management personnel with annual incentive awards, the payment of which is tied to the achievement of specified Company objectives. Payouts of the award were in cash and were dependent entirely on the achievement of the corporate goals that were established by the Committee in January 2004.

For Messrs. Moore, Strecker and Delaney, the three most senior executive officers of the Company at the time the corporate goals were established, the corporate 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 consolidated net income of Enogex and its subsidiaries (the “Unregulated Income Target”). These three corporate goals were also used in establishing the corporate goals for all other executive officers. However, the weighting of the goals was slightly different for the remaining executive officers, with the corporate goals for one executive officer being based 50% on the Earnings Target and 50% on the O&M/Capital Target while for the remaining executive officers the corporate goals were based 50% on the Earnings Target, with the remaining 50% allocated between the O&M/Capital Target and the Unregulated Income Target based on the responsibilities of the individual’s position.

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 corporate goals, to receive from 0% to 150% of such targeted amount. For 2004, the targeted amount ranged from 25% to 75% of base salary and approximated the 50th percentile of the level of such awards granted to comparable executives in the Blended Industry Survey Group.

The percentage of the targeted amount that an officer ultimately received based on corporate performance was subject to being decreased, but not increased, at the discretion of the Committee. For 2004, corporate performance of the Earnings Target, the O&M/ Capital Target and the Unregulated Income Target exceeded the minimum levels of achievement established by the Committee and resulted in total payouts under the Annual Incentive Plan to executive officers ranging from 32.3% to 99.5% of their base salaries and from approximately 115.5% to 132.7% of their targeted amounts. Payouts under the Annual Incentive Plan are reflected in the bonus column of the Summary Compensation Table on page 19.

Long-Term Awards. Another significant component of executive compensation in 2004 was long-term awards under our Company’s Stock Incentive Plan, which also was approved by the shareowners at the 2003 Annual Meeting. 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 2004, the Committee made awards of stock options and performance units. In making awards of stock options and performance units, the Committee considered numerous factors as discussed below and reviewed the expected value of long-term compensation payable to executives in the 50th percentile of the Energy Services Survey Group and the 50th percentile of the Blended Industry Survey Group. The expected value of long-term compensation payable to the most senior level executives in the 50th percentile of the Blended Industry Survey Group was substantially higher than the expected value of long-term compensation payable to comparable executives in the 50th percentile of the Energy Services Survey Group and substantially higher than the expected value of long-term compensation awarded by the Committee in the past to comparable executive officers at the Company. While the Committee intends to continue to consider the long-term compensation payable to comparable executives in the 50th percentile of the Blended Industry Survey Group in awarding long-term compensation to the Company’s executive officers, the Committee’s intent generally in 2004 was to provide executive officers with an aggregate value of long-term compensation equal to the expected value of long-term incentives payable to comparable executives in the 50th percentile of the Energy Services Survey Group.

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.

The stock options were granted to executive officers during the first quarter of 2004 at an exercise price equal to the fair market value at the date of the grant. The options have a ten-year term and vest over three years, with one-third of the options becoming exercisable at the end of each year. Since options were granted with an exercise price equal to the market value of our Common Stock at the time of grant, they provide no

value unless our stock price increases after the options are granted. These awards are thus tied to stock price appreciation in excess of the stock’s value at time of grant, rewarding executives as if they shared in the ownership of the Company. The number of shares subject to options for each executive officer was determined by taking the expected value to be provided in options, as determined above, and dividing that amount by the estimated current value of an option for our stock using a variation of the Black-Scholes Option Pricing methodology provided by the Committee’s outside compensation consultant. This resulted in executive officers receiving stock options with an estimated value of approximately 6.25% to 37.5% of their 2004 base salaries.

The performance units also were granted to executive officers during the first quarter of 2004. The number of performance units granted was determined by taking the amount of the executive’s long-term award to be delivered in performance units (adjusted on a present value basis), as determined above, and dividing that amount by a recent closing price for the Company’s Common Stock. This resulted in executives receiving performance units with an expected value at the date of grant of from 18.75% to 112.5% of their 2004 base salaries. The value of the performance units is substantially dependent upon the changing value of the Company’s Common Stock in the marketplace. The terms of the performance units granted in 2004 were substantially the same as the terms of the performance units granted in 2003. Each executive officer is entitled to receive from 0% to 200% of the performance units contingently awarded to the executive based on the Company’s total shareholder return over a three-year period (defined as share price increase plus dividends paid, divided by share price at beginning of the period) measured against the total shareholder return for such period (“TSR”) by 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.

CEO Compensation. The 2004 compensation for Mr. Moore consisted of the same components as the compensation for other executive officers. Mr. Moore’s 2004 salary remained unchanged from the 2002 and 2003 amount of $710,000, and his 2004 targeted award under the Annual Incentive Plan remained at 75% of this base salary, which the Compensation Committee believed were appropriate levels based on his performance and his prior experience. As a result of 2004 corporate performance of the corporate goals described above, he received a payout of $706,747 under the Annual Incentive Plan, representing approximately 99.5% of his base salary and 132.7% of his targeted award. The award of stock options and performance units 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. Consideration also was given 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. Based on these factors, the Committee determined to grant Mr. Moore stock options and performance units having an expected value of approximately 150% of his 2004 base salary, of which 25% was awarded in stock options and 75% in performance units.

Other Benefits. Virtually all of our employees, including executive officers, are eligible to participate in the Retirement Savings Plan and pension plan. Both the Retirement Savings Plan and pension plan have supplemental restoration plans that enable executive officers to receive the same benefits that they would have received in the absence of limitations imposed by the federal tax laws on contributions or payouts. In addition, a Supplemental Executive Retirement Plan (the “SERP”), which was adopted in 1993, offers attractive pension benefits to lateral hires. No officer, other than Mr. Delaney, participated in the SERP during 2004. The SERP is not expected to benefit other existing executive officers generally who remain employed by the Company or OG&E until age 65. In reviewing the benefits under the SERP, Retirement Savings Plan, pension plan and related restoration plans, the Committee sought in 2004 to provide participants with benefits at least commensurate with those offered by other utilities of comparable size. The restoration plans for the Retirement Savings Plan and pension plan contain provisions requiring their immediate funding in the event of certain mergers, consolidations or tender offers involving the Company.

Stock Ownership Guidelines. In an effort to further align management’s interests with those of the shareowners, 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, President and Chief Executive Officer 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 and the number of shares necessary to satisfy the guidelines is based on an assumed valuation of $25 per share. Similar guidelines were

adopted for members of the Board of Directors at a level of six times their annual retainer.

Conclusion. The Committee believes that our Company’s executive compensation system serves the interests of the Company and our shareowners effectively. The Committee takes very seriously its responsibilities with respect to our executive compensation system. To this end, the Committee will continue to monitor and revise the compensation policies as necessary to ensure that our compensation system continues to meet the needs of the Company and our shareowners.

Compensation Committee
Luke R. Corbett, Chairman
Herbert H. Champlin, member
Martha W. Griffin, member
John D. Groendyke, member
Robert Kelley, member
Ronald H. White, M.D. member

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 and five other most highly compensated executive officers for the past three years. To the extent the table shows zeros for other annual compensation or payouts under long-term incentive plans for a particular year, no amounts were required to be reported in such year or, in the case of other annual compensation, the amounts were below the threshold required for disclosure under the SEC’s rules.


					Long-Term Compensation
		Annual Compensation			Awards		Payouts
				Other	Restricted	Securities
				Annual	Stock	Underlying	LTIP	All Other
Name and Principal		Salary	Bonus(1)	Compensation(2)	Awards(3)	Options/	Payouts	Compensation(4)
Position	Year	($)	($)	($)	($)	SAR (#)	($)	($)

S.E. Moore, Chairman,	2004	710,000	706,747	0	0	85,100	0	81,753
President and	2003	710,000	772,817	0	0	202,300	0	48,558
Chief Executive Officer	2002	710,000	149,885	0	0	218,500	0	35,361

A.M. Strecker	2004	191,667	165,350	0	0	40,500	0	34,690
Former Executive Vice	2003	460,000	433,939	0	0	90,400	0	37,174
President and Chief	2002	460,000	84,161	0	0	97,600	0	26,186
Operating Officer (5)

P.B. Delaney (6)	2004	440,000	350,387	0	0	44,000	0	43,192
Executive Vice President	2003	400,000	348,312	0	0	98,200	0	16,705
and Chief Operating Officer	2002	300,000	24,192	0	0	84,900	0	156,577

J.R. Hatfield	2004	310,000	200,264	0	0	21,100	0	20,970
Sr. Vice President and	2003	310,000	221,932	0	0	51,800	0	28,151
Chief Financial Officer	2002	310,000	52,205	0	0	55,900	0	16,921

J.T. Coffman	2004	260,000	120,064	0	0	13,500	0	24,547
Sr. Vice President	2003	255,000	143,065	0	0	30,100	0	26,701
Power Supply	2002	255,000	8,883	0	0	32,500	0	20,036

S.R. Gerdes	2004	220,000	77,220	0	0	9,700	0	25,234
Vice President	2003	200,000	85,909	0	0	15,700	0	29,386
Utility Operations	2002	195,000	38,406	0	0	14,500	0	10,584

(1)	As explained on page 15, amounts in this column reflect payouts under the Annual Incentive Compensation Plan.
(2)	Each of the executive officers receives certain personal benefits, including reimbursement for tax and estate planning, and club memberships. The value of these personal benefits received by each of the Named Executive Officers is below the reporting threshold contained in the Securities and Exchange Commission’s rules and, thus, is not included in this column.
(3)	No shares of Restricted Stock were awarded in 2002, 2003 or 2004, however, shares of restricted stock had been awarded in prior years. In the absence of death, disability or normal retirement, the shares awarded to these individuals are subject to forfeiture for three years with the amount the recipient ultimately receives dependent on Company performance. The total number of shares and market value of Restricted Stock held by each of the named individuals as of December 31, 2004, were as follows: Mr. Moore, 12,889 shares, $341,687; Mr. Strecker, 5,759 shares, $152,671; Mr. Delaney, 0 shares, $0; Mr. Hatfield, 3,299 shares, $87,456; Mr. Coffman, 1,915 shares, $50,767; and Mr. Gerdes, 854 shares, $22,640. Dividends are paid to these individuals on the shares of Restricted Stock owned by them.
(4)	Amounts in this column for 2004 reflect: (i) for Mr. Moore, $66,727 (Retirement Savings Plan and Deferred Compensation Plan) and $15,026 (insurance premiums); (ii) for Mr. Strecker, $28,152 (Retirement Savings Plan and Deferred Compensation Plan) and $6,538 (insurance premiums); (iii) for Mr. Delaney, $38,040 (Retirement Savings Plan and Deferred Compensation Plan) and $5,152 (insurance premiums); (iv) for Mr. Hatfield, $15,958 (Retirement Savings Plan and Deferred Compensation Plan) and $5,012 (insurance premiums); (v) for Mr. Coffman, $18,138 (Retirement Savings Plan and Deferred Compensation Plan) and $6,409 (insurance premiums); and (vi) for Mr. Gerdes, $13,766 (Retirement Savings Plan and Deferred Compensation Plan) and $11,468 (insurance premiums). A significant portion of the insurance premiums reported for each of these individuals is for life insurance policies and such premiums are recovered by the Company from the proceeds of the policies. Amounts shown as Retirement Savings Plan and Deferred Compensation Plan represent Company contributions for the individual under those plans.
(5)	Mr. Strecker retired from the Company, effective June 1, 2004. See “Employment Agreements and Change of Control Agreements” for a summary of Mr. Strecker’s consulting agreement with the Company after his retirement.
(6)	Mr. Delaney joined the Company effective April 1, 2002.

OPTIONS AND STOCK APPRECIATION RIGHTS (SARs)

The following table indicates for each of the named executives (i) the extent to which the Company used stock options and SARs for executive compensation purposes in 2004 and (ii) the potential value of such options and SARs as determined pursuant to the SEC rules.


Options and SARs Granted in 2004
					Potential Realizable Value
					at Assumed Annual Rates
					of Stock Price
	Individual Grants				Appreciation for Option Term

(a)	(b)	(c)	(d)	(e)	(f)	(g)
		% of Total Options
		and SARs Granted to	Exercise or
	Options/SARs	Employees	Base Price	Expiration
Name	Granted #⁽¹⁾	in 2004	($/Share)	Date	5%($)⁽²⁾	10%($)⁽²⁾

S.E. Moore	85,100	22.37	$23.67	1/24/14	$1,274,878	$3,218,387
A.M. Strecker	40,500	10.65	23.67	1/24/14	606,728	1,531,665
P.B. Delaney	44,000	11.57	23.67	1/24/14	659,161	1,664,031
J.R. Hatfield	21,100	5.55	23.67	1/24/14	316,098	797,976
J.T. Coffman	13,500	3.55	23.67	1/24/14	202,243	510,555
S.R. Gerdes	9,700	2.55	23.67	1/24/14	145,315	366,843

⁽¹⁾	Options were granted on January 24, 2004 and become exercisable in one-third annual installments beginning one year from the date of grant. No SARs were awarded for 2004.
⁽²⁾	The hypothetical potential appreciation shown in columns (f) and (g) for the named executives is required by the SEC rules. The amounts in these columns do not represent either the historical or anticipated future level of appreciation of our Common Stock.

The following table indicates for each of the named executives the number and value of exercisable and unexercisable options and SARs as of December 31, 2004.


Aggregated Option and SAR Exercises in 2004 and FY-End Option/SAR Value
(a)	(b)	(c)	(d)		(e)
			Number of Unexercised		Value of Unexercised In-the-
			Options and SARs at 12/31/04		Money Options and SARs at
	Shares Acquired on	Realized	(#) - Exercisable (ex)/		12/31/04 ($) - Exercisable (ex)/
Name	Exercise (#)	Value ($)	Unexercisable (unex)		Unexercisable (unex) *

S.E. Moore	N/A	N/A	572,399	(ex)	$ 2,427,495	(ex)
			292,801	(unex)	$ 1,886,566	(unex)

A.M. Strecker	60,265	$524,731	296,135	(ex)	$ 1,037,769	(ex)
			0	(unex)	$ 0	(unex)

P.B. Delaney	10,000	$ 83,750	79,300	(ex)	$ 438,998	(ex)
			137,767	(unex)	$ 880,176	(unex)

J.R. Hatfield	35,166	$232,665	87,266	(ex)	$ 254,335	(ex)
			74,268	(unex)	$ 480,979	(unex)

J.T. Coffman	10,033	$ 74,395	68,566	(ex)	$ 175,136	(ex)
			44,401	(unex)	$ 283,150	(unex)

S.R. Gerdes	N/A	N/A	46,099	(ex)	$ 196,514	(ex)
			25,001	(unex)	$ 151,997	(unex)

Share price on December 31, 2004 was $26.51. Options vest over three years with one-third becoming exercisable at the end of each year. Unexercisable options were granted on January 16, 2002 at a price of $22.23, January 27, 2003 at a price of $16.685, and January 24, 2004 at a price of $23.575. No SARs were granted in 2004.

Long-Term Incentive Plans—Awards In Last Fiscal Year

(a)	(b)	(c)	(d)	(e)	(f)

			Estimated future payouts under non-stock
	Number of	Performance or other period		price-based plans
	shares, units	until
	or other	maturation or	Threshold	Target	Maximum
Name	rights (#)(1)	payout(2)	(#)(2)	(#)(2)	(#)(2)

S.E. Moore	36,376	1/1/04-12/31/06	0	36,376	72,752
A.M. Strecker	2,400	1/1/04-12/31/06	0	2,400	4,800
P.B. Delaney	18,786	1/1/04-12/31/06	0	18,786	37,572
J.R. Hatfield	9,000	1/1/04-12/31/06	0	9,000	18,000
J.T. Coffman	5,772	1/1/04-12/31/06	0	5,772	11,544
S.R. Gerdes	4,132	1/1/04-12/31/06	0	4,132	8,264


(1)	Represents awards of performance units made under the Stock Incentive Plan. Each performance unit represents the value of one share of our common stock.

(2)	The number of performance units ultimately received at the end of the performance cycle is based on the Company’s total shareholder return over a three-year period measured against the total shareholder return for such period by a peer group selected by the Committee. Following the end of the performance cycle, the performance units will be paid out two-thirds in shares of our common stock and one-third in cash.

PENSION PLAN TABLE

The Company and OG&E maintain a qualified non-contributory pension plan (the “Retirement Plan”) covering all employees who have completed one year of service. Subject to limitations imposed by the Employee Retirement Income Security Act of 1974 (“ERISA”), benefits payable under the Retirement Plan 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 bonus) 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, bonuses 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 time of retirement to receive, in lieu of an annuity, a lump-sum payment equal to the present value of the annuity. Also, for employees hired after January 31, 2000, the pension 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. 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 who have completed five or more years of service before terminating their employment and to participants after reaching retirement age upon total and permanent disability. As indicated above, the benefits payable under the Plan are subject to maximum limitations under ERISA. Should benefits for a participant at the time of retirement exceed the then permissible limits of ERISA, the Retirement Restoration Plan will provide benefits through a lump-sum distribution actuarially equivalent to the amounts that would have been payable to such participant annually under the Retirement Plan but for the ERISA limits. The Company and OG&E fund the estimated benefits payable under the Retirement Restoration Plan through contributions to a trust for the benefit of those employees who will be entitled to receive payments under the Retirement Restoration Plan.

The following table sets forth the estimated annual benefits payable upon normal retirement under the Retirement Plan and Retirement Restoration Plan to persons in the compensation classification specified.
Average
Compensation	Years of Service at Retirement
5 Highest Years	10	15	20	25	30	35	40	45
$ 125,000	$ 16,501	$ 24,752	$ 33,002	$ 41,253	$ 49,504	$ 57,754	$ 66,005	$ 74,255
150,000	20,251	30,377	40,502	50,628	60,754	70,879	81,005	91,130
175,000	24,001	36,002	48,002	60,003	72,004	84,004	96,005	108,005
200,000	27,751	41,627	55,502	69,378	83,254	97,129	111,005	124,880
225,000	31,501	47,252	63,002	78,753	94,504	110,254	126,005	141,755
250,000	35,251	52,877	70,502	88,128	105,754	123,379	141,005	158,630
300,000	42,751	64,127	85,502	106,878	128,254	149,629	171,005	192,380
350,000	50,251	75,377	100,502	125,628	150,754	175,879	201,005	226,130
400,000	57,751	86,627	115,502	144,378	173,254	202,129	231,005	229,880
450,000	65,251	97,877	130,502	163,128	195,754	228,379	261,005	293,630
500,000	72,751	109,127	145,502	181,878	218,254	254,629	291,005	327,380
600,000	87,751	131,627	175,502	219,378	263,254	307,129	351,005	394,880
700,000	102,751	154,127	205,502	256,878	308,254	359,629	411,005	462,380
800,000	117,751	176,627	235,502	294,378	353,254	412,129	471,005	529,880
900,000	132,751	199,127	265,502	331,878	398,254	464,629	531,005	597,380
1,000,000	147,751	221,627	295,502	369,378	443,254	517,129	591,005	664,880
1,100,000	162,751	244,127	325,502	406,878	488,254	569,629	651,005	732,380
1,200,000	177,751	266,627	355,502	444,378	553,254	622,129	711,005	779,880
1,300,000	192,751	289,127	385,502	481,878	578,254	674,629	771,005	867,380
1,400,000	207,751	311,627	415,502	519,378	623,254	727,129	831,005	934,880
1,500,000	222,751	334,127	445,502	556,878	668,254	779,629	891,005	1,002,380
1,600,000	237,751	356,627	475,502	594,378	713,254	832,129	951,005	1,069,880
1,700,000	252,751	379,127	505,502	631,878	758,254	884,629	1,011,005	1,137,380
1,800,000	267,751	401,627	535,502	669,378	803,254	937,129	1,071,005	1,204,880
1,900,000	282,751	424,127	565,502	706,878	848,254	989,629	1,131,005	1,272,380

As of December 31, 2004, the credited years of service for the individuals listed in the Summary Compensation Table on page 19 are as follows: S. E. Moore – 30 years; A. M. Strecker – 33 years; P. B. Delaney – 2 years; J. R. Hatfield – 10 years; J. T. Coffman – 34 years; and S. R. Gerdes – 26 years.

In 1993, OG&E adopted a SERP which is an unfunded supplemental plan that is not subject to the benefits limit imposed by ERISA. 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 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 2004.

EMPLOYMENT AGREEMENTS AND CHANGE OF CONTROL ARRANGEMENTS

Effective April 1, 2002, Mr. Peter Delaney entered into a three-year employment agreement with the Company. The agreement expired by its terms on March 31, 2005. Under the terms of the agreement, Mr. Delaney was to serve as an Executive Vice President of the Company and as the Chief Executive Officer of the Company’s unregulated businesses. Mr. Delaney was entitled to an annual base salary of not less than $400,000, an annual target award under the annual incentive plan of at least $240,000 (60% of his initial base salary) and an annual target award under the stock incentive plan of at least $400,000 (100% of his initial base salary). In addition, Mr. Delaney was entitled to (i) participate in all employee benefit plans and fringe benefits of the Company or an affiliate provided generally to executives of the Company, (ii) relocation expenses and (iii) participate in the Company’s Supplemental Executive Retirement Plan (which is described on page 22).

Under the agreement, if Mr. Delaney’s employment had terminated prior to March 31, 2005, he was entitled to various payments and benefits depending on whether his termination was due to death, disability, cause or some other reason. These provisions are no longer applicable, because, as noted above, the agreement expired by its terms on March 31, 2005, with Mr. Delaney continuing to serve as Executive Vice President and Chief Operating Officer of the Company.

Effective June 1, 2004, Mr. A.M. Strecker, former Executive Vice President and Chief Operating Officer, entered into a consulting agreement with the Company. The term of the agreement extends to May 31, 2005. Under the terms of the agreement, Mr. Strecker agreed to consult and advise the Company on specific matters designated by the chief executive officer and chief operating officer. In consideration for services provided under the agreement, Mr. Strecker was paid a lump sum retainer of $18,500 and $230 per hour, plus reasonable out-of-pocket expenses, for consulting services performed at the request of the chief executive officer or chief operating officer. The $230 per hour represented Mr. Strecker’s annual salary at the time of his retirement ($460,000) divided by 2,000 hours. Mr. Strecker worked 201 hours in 2004 and the payment of $46,230 for such services at $230 per hour was deferred until the termination of his consulting agreement on May 31, 2005.

The Company and OG&E also have entered into employment agreements with each officer of the Company and OG&E. 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 (a) such officer prior to the change of control or (b) other peer executives of the Company. In addition, upon a change of control, Mr. Delaney will be considered vested under the Supplemental Executive Retirement Plan if he has not already attained age 55.

If, during the Employment Period, the officer’s employment is terminated by the employer for reasons other than cause or disability or by such officer due to a change in employment responsibilities, the officer is entitled to the following payments: (i) all accrued and unpaid compensation 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 the foregoing 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 Internal Revenue Code of 1986, as amended, then the severance benefits will be reduced 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. A change of control encompasses certain mergers and acquisitions, changes in Board membership and acquisition of securities of the Company.

COMPANY STOCK PERFORMANCE

The following graph shows a five-year comparison of cumulative total returns for the Company’s Common Stock, the S&P 500 Index and the S&P 500 Electric Utilities Index. The graph assumes that the value of the investment in the Company’s Common Stock and each index was 100 at December 31, 1999, and that all dividends were reinvested. As of March 1, 2005, the closing price of the Company’s Common Stock on the New York Stock Exchange was $26.10.

[PERFORMANCE GRAPH OMITTED]

	1999	2000	2001	2002	2003	2004
OGE Energy Corp.	100	137	138	112	165	191
S&P 500 Index	100	91	80	62	80	89
S&P 500 Electric Utilities	100	154	128	109	135	171

SECURITY OWNERSHIP

The following table shows the number of shares of the Company’s Common Stock beneficially owned on March 1, 2005, by each Director, by each of the Executive Officers named in the compensation table on page 19, and by all Executive Officers and Directors as a group:
	Number of Common		Number of Common
	Shares(1) (2) (3)		Shares(1) (2) (3)

Herbert H. Champlin	50,583	S.E. Moore	860,913
Luke R. Corbett	32,147	A.M. Strecker	324,806
William E. Durrett	28,569	P.B. Delaney	168,481
Martha W. Griffin	28,572	J.R. Hatfield	148,663
John D. Groendyke	29,945	J.T. Coffman	118,478
Robert Kelley	42,859	S.R. Gerdes	69,023
Linda Petree Lambert	1,645	All Executive Officers and
Ronald H. White, M.D.	38,794	Directors as a group
J.D. Williams	23,849	(23 persons)	2,198,431

(1)	Ownership by each executive officer is less than .96% of the class, by each director other than Mr. Moore is less than .06% of the class and, for all executive officers and directors as a group, is less than 2.44% of the class. Amounts shown include shares for which, in certain instances, an individual has disclaimed beneficial interest. Amounts shown for executive officers include 1,815,258 shares of Common Stock representing their interest in shares held under the Company’s Retirement Savings Plan, Officer’s Deferred Compensation Plan, and Stock Incentive Plan for which in certain instances they have voting power but not investment power.
(2)	Amounts shown for Messrs. Champlin, Corbett, Durrett, Groendyke, Kelley, White and Williams and for Mrs. Griffin and Ms. Lambert include, 42,961; 26,705; 19,109; 4,445; 25,759; 31,694; 6,723; 17,812 and 1,645 common stock units, respectively, under the Directors’ Deferred Compensation Plan.
(3)	Includes shares subject to stock options granted under the Company’s Stock Incentive Plan, exercisable within 60 days following March 1, 2005, as follows: each non-officer director except Mr. Groendyke and Ms. Lambert, 5,100 shares; Mr. Groendyke and Ms. Lambert, 0 shares; Mr. Moore, 741,032 shares; Mr. Strecker, 296,135 shares; Mr. Delaney, 155,032 shares; Mr. Hatfield, 130,200 shares; Mr. Coffman, 93,933; and Mr. Gerdes, 59,399 shares.

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. As explained in the Report of the Compensation Committee on page 17, the committee recommended and the Board of Directors adopted stock ownership guidelines in 2004 for directors and officers.

EQUITY COMPENSATION PLAN INFORMATION
The following table provides certain information as of December 31, 2004 with respect to the shares of the Company’s Common Stock that may be issued under the existing equity compensation plans:

	A	B	C
			Number of Securities
	Number of		Remaining Available
	Securities to be		for future issuances
	Issued upon	Weighted	under equity
	Exercise of	Average Price	compensation plans
Plan Category	Outstanding	of Outstanding	(excluding securities
	Options	Options	reflected in Column A)
Equity Compensation Plans
Approved by
Shareowners (1)	2,827,914	$22.16	2,209,763(2)
Equity Compensation Plans
Not Approved by
Shareowners	0	N/A	N/A

(1)	Consists of the OGE Energy Corp. Stock Incentive Plan, which was approved by shareowners at the 1998 annual meeting, and the OGE Energy Corp. 2003 Stock Incentive Plan, which was approved by shareowners at the 2003 annual meeting.
(2)	Awards under the Stock Incentive Plan can take the form of stock options, stock appreciation rights, restricted stock or performance units.

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. Except as described in the immediately succeeding two sentences, to our knowledge, all of our directors and officers subject to such reporting obligations have satisfied their reporting obligations in full for 2004. Messrs. Delaney, Hatfield, Coffman and Perkins each failed to timely file one report on Form 4 regarding the accrual of phantom stock units under the Company’s deferred compensation plan. They each filed the required Form 4 approximately two weeks late.

SHAREOWNER PROPOSALS

Any shareowner proposal intended to be included in the proxy statement for the Annual Meeting in 2006 must be received by the Company on or before December 1, 2005. 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 2006 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:

o	a brief description of the business you desire to bring before the Annual Meeting and your reasons for conducting such business at the Annual Meeting,

o	your name and address,

o	the number of shares of Common Stock which you beneficially own, and

o	any material interest you may have in the business being proposed.

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 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 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 Annual Report to Shareowners or this proxy statement, please call or write us at the following address or phone number: OGE Energy Corp. Shareowner Relations, 321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101-0321 or phone 405-553-3211. 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 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 or write us at the following address or phone number: OGE Energy Corp. Shareowner Relations, 321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101-0321 or phone 405-553-3211. If you want to receive separate copies of the 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.

LOCATION OF THE NATIONAL COWBOY AND WESTERN HERITAGE MUSEUM

East Bound or West Bound I-44

Exit to Martin Luther King Ave., continuing north approximately .2 miles. Proceed west
on Northeast 63rd Street .5 miles to National Cowboy and Western Heritage Museum.

MAP

Annex A

OGE ENERGY CORP.

AUDIT COMMITTEE CHARTER

Purposes

The purposes of the Audit Committee of the Board of Directors of OGE Energy Corp. (the “Company”) are to assist the Board of Directors in monitoring: (i) the integrity of the Company’s financial statements, (ii) the Company’s compliance with legal and regulatory requirements, (iii) the independent auditors’ qualifications and independence, and (iv) the performance of the independent auditors and the Company’s internal audit function. The Committee also shall prepare the Committee’s report, made pursuant to the Securities Exchange Act of 1934 (the “Exchange Act”), to be included in the Company’s annual proxy statement (the “Audit Committee Report”).

Composition

Size. The size of the Committee shall be determined by the Board of Directors, but it always must have at least three members.

Qualifications. Each Committee member shall have all of the following qualifications:

Each Committee member shall meet the independence criteria of (a) the rules of the New York Stock Exchange, Inc. (“NYSE”), as such requirements are interpreted by the Board of Directors in its business judgment, and (b) Section 301 of the Sarbanes-Oxley Act of 2002 and the rules and listing requirements promulgated thereunder by the Securities and Exchange Commission (“SEC”), including Rule 10A-3 under the Exchange Act, and the NYSE.

Each Committee member shall be financially literate or shall become financially literate within a reasonable period of time after his or her appointment to the Committee. Additionally, at least one member of the Committee shall have accounting or related financial management expertise sufficient to meet the criteria of a financial expert within the meaning of Section 407 of the Sarbanes- Oxley Act of 2002 and any rules promulgated thereunder by the SEC. The Board of Directors shall determine, in its business judgment, whether a member is financially literate and whether at least one member has the requisite accounting or financial management expertise and meets the financial expert criteria of Section 407 of the Sarbanes-Oxley Act of 2002 and any rules promulgated thereunder by the SEC. The designation or identification of a person as an audit committee financial expert shall not (a) impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the Audit Committee and Board of Directors in the absence of such designation or identification, or (b) affect the duties, obligations or liability of any other member of the Audit Committee or Board of Directors.

Each Committee member shall receive as compensation from the Company only those forms of compensation as are not prohibited by Section 301 of the Sarbanes-Oxley Act of 2002 and the rules and listing requirements promulgated thereunder by the SEC and the NYSE. Permitted compensation includes (a) director’s fees (which includes all forms of compensation paid to directors of the Company for service as a director or member of a Board Committee) and/or (b) fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Company provided that such compensation is not contingent in any way on continued service. Additional directors’ fees may be paid to Audit Committee members to compensate them for the significant time and effort they expend in performing their duties as Audit Committee members.

If a Committee member simultaneously serves on the audit committee of more than three public companies (including the Company), the Board of Directors must determine that such simultaneous service would not impair the ability of such member to effectively serve on the Committee. The Company shall disclose any such determination in its annual proxy statement.

A-1

Selection. The Board of Directors will appoint the members and the Chair of the Committee. Each Committee member will serve at the pleasure of the Board and for such term as the Board may decide or until such Committee member is no longer a Board member. Committee members may be replaced by the Board at any time.

Duties and Responsibilities

The Committee is responsible for overseeing the Company’s financial reporting process on behalf of the Board of Directors and preparing the Audit Committee Report. While the Audit Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Committee to plan or conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate and are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the independent auditors.

The Committee is directly responsible for the appointment, termination, compensation, retention, evaluation and oversight of the work of the Company’s independent auditors (including resolution of disagreements between management and the auditors regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Company.

In performing its responsibilities, the Committee shall:

Retain the Independent Auditors: The Committee has the sole authority to (a) directly appoint, retain, compensate, evaluate and terminate the Company’s independent auditors, (b) approve all audit services (including the fees and terms thereof), and (c) approve any permitted non-audit services (including the fees and terms thereof). The Committee is to exercise this authority in a manner consistent with Sections 201, 202 and 301 of the Sarbanes-Oxley Act of 2002 and the rules and listing standards promulgated thereunder by the SEC and NYSE. The Committee may form and delegate authority to subcommittees consisting of one or more members when appropriate, including the authority to grant any pre-approvals of all audit and permitted nonaudit services, provided that decisions of such subcommittee to grant pre-approvals shall be presented to the Committee at its next scheduled meeting. Prior to retaining the independent auditors, the Committee shall evaluate the auditors’ qualifications, performance and independence, which evaluation shall include, among other things, a review of the auditors’ prior work for the Company, consideration of the opinions of management and the internal auditors, and a review of the reports and other information described in paragraphs (2) and (3) below. The Committee shall report its conclusions with respect to the independent auditors to the Board.

Review and Discuss the Auditors’ Quality Control: The Committee is to, at least annually, obtain and review a report by the independent auditors describing (a) the audit firm’s internal quality control procedures, (b) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and (c) any steps taken to deal with any such issues.

Review and Discuss the Independence of the Auditors: In connection with the retention of the Company’s independent auditors, the Committee is to, at least annually, review and discuss the information and reports provided by management or the auditors relating to the independence of the audit firm, including, among other things, information related to the non-audit services provided and expected to be provided by the auditors and other relationships between the independent auditors and the Company. The Committee is responsible for (a) ensuring that the independent auditors submit at least annually to the Committee a formal written statement delineating all relationships between the auditors and the Company consistent with applicable independence standards, (b) engaging in a dialogue with the auditors with respect to any disclosed relationship or services that may impact the objectivity and independence of the auditors, and (c) taking appropriate action in response to the auditors’ report to satisfy itself of the auditors’ independence. In connection with the Committee’s evaluation of the independent auditors, the Committee shall review and evaluate the lead partner of the independent auditors and shall cause the regular rotation, to the extent required by Section 10(A)(j) of the Exchange Act, of the audit partners who

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serve on the Company’s audit engagement team. The Committee also will consider whether, in order to assure continuing auditors’ independence, it is appropriate to adopt a policy of rotating the independent auditing firm on a regular basis.

Set Hiring Policies: The Committee is to set hiring policies for employees or former employees of the independent auditors, which include the restrictions set forth in Section 206 of the Sarbanes- Oxley Act of 2002 and any rules promulgated thereunder by the SEC.

Review and Discuss the Audit Plan: The Committee is to review and discuss with the independent auditors the plans for, and the scope of, the annual audit and other examinations, including the adequacy of staffing and compensation.

Review and Discuss Conduct of the Audit: The Committee is to review and discuss with the independent auditors the matters required to be discussed by Statement on Auditing Standards No. 61 relating to the conduct of the audit, as well as any audit problems or difficulties the auditor encountered in the course of the audit work and management’s response, including (a) any restriction on audit scope or the auditors’ activities or on access to requested information, (b) any disagreements with management, (c) significant issues discussed with the independent auditors’ national office and (d) whether the auditors have any reason to believe there has been conduct in violation of Rule 13b2-2 under the Exchange Act. The Committee is to decide all unresolved disagreements between management and the independent auditors regarding financial reporting.

Review and Discuss Financial Statements and Disclosures: The Committee is to review and discuss with appropriate officers of the Company and the independent auditors the annual audited and quarterly financial statements of the Company, including reviewing (a) the Company’s specific disclosures under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and (b) the disclosures regarding internal controls and other matters required by Section 302 and 404 of the Sarbanes-Oxley Act of 2002 and any rules promulgated thereunder by the SEC. The Committee shall recommend to the Board whether the audited financial statements of the Company should be included in the Company’s Form 10-K.

Review and Discuss Earnings Press Releases: The Committee is to review and discuss earnings and other financial press releases (including any use of “pro forma” or “adjusted” non-GAAP information), as well as financial information and earnings guidance provided to analysts and rating agencies (which review may occur after issuance and may be done generally as a review of the types of information to be disclosed and the form of presentation to be made).

Review and Discuss Internal Audit Plans and Senior Internal Auditing Executive: The Committee is to review and discuss with the senior internal auditing executive and appropriate members of the staff of the internal auditing department the plans for and the scope of their ongoing audit activities, including adequacy of staffing and compensation. The Committee also is to review the appointment and replacement of the senior internal auditing executive.

10)

Review and Discuss Internal Audit Reports: The Committee is to review and discuss with the senior internal auditing executive and appropriate members of the staff of the internal auditing department the annual report of the audit activities, examinations and results thereof of the internal auditing department.

11)

Review and Discuss the Systems of Internal Accounting Controls: The Committee is to review and discuss with the independent auditors, the senior internal auditing executive, the General Counsel and, if and to the extent deemed appropriate by the Chair of the Committee, members of their respective staffs the adequacy of the Company’s internal accounting controls, the Company’s financial, auditing and accounting organizations and personnel, and the Company’s policies and compliance procedures with respect to business practices, which shall include (a) by Sections 302 and 404 of the Sarbanes-Oxley Act of 2002 and any rules promulgated thereunder by the SEC, and (b) a review with the independent auditors of their attestation of management’s

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assessment of internal controls over financing reporting and the independent auditors’ analysis of the adequacy of disclosures about changes in internal control over financial reporting.

12)

Review and Discuss the Recommendations of Independent Auditors: The Committee is to review and discuss with the senior internal auditing executive and the appropriate members of the staff of the internal auditing department recommendations made by the independent auditors and the senior internal auditing executive, as well as such other matters, if any, as such persons or other officers of the Company may desire to bring to the attention of the Committee.

13)

Review and Discuss the Audit Results: The Committee is to review and discuss with the independent auditors (A) the report of their annual audit, or proposed report of their annual audit, (B) the accompanying management letter, if any, (C) the reports of their reviews of the Company’s interim financial statements conducted in accordance with Statement on Auditing Standards No. 71, and (D) the reports of the results of such other examinations outside of the course of the independent auditors’ normal audit procedures that the independent auditors may from time to time undertake. The foregoing shall include the reports required by Section 204 of the Sarbanes- Oxley Act of 2002 and any rules promulgated thereunder by the SEC and, as appropriate, a review of (a) major issues regarding (i) accounting principles and financial statement presentations, including any significant changes in the Company’s selection or application of accounting principles and (ii) the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies, (b) analyses prepared by management and/or the independent auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative GAAP methods on the financial statements, and (c) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements of the Company.

14)

Obtain Assurances under Section 10A(b) of the Exchange Act: The Committee is to obtain assurance from the independent auditors that in the course of conducting the audit, there have been no acts detected or that have otherwise come to the attention of the audit firm that require disclosure to the Committee under Section 10A(b) of the Exchange Act.

15)

Discuss Risk Management Policies: The Committee is to discuss with management the Company’s major financial risk exposures and the steps management has taken to monitor and control the exposures, including the Company’s risk assessment and risk management policies and guidelines.

16)

Obtain Reports Regarding Conformity With Legal Requirements and the Company’s Code of Business Conduct and Ethics: The Committee is to periodically obtain reports from management, the Company’s senior internal auditing executive and the independent auditor that the Company and its affiliated entities are in conformity with applicable legal requirements and the Company’s Code of Ethics (including the Code of Ethics for CEO and Senior Financial Officers). The Committee is to review and discuss reports of insider and affiliated party transactions. The Committee should advise the Board with respect to the Company’s policies and procedures regarding compliance with applicable laws and regulations and with the Company’s Code of Ethics (including the Code of Ethics for CEO and Senior Financial Officers).

17)

Establish Procedures for Complaints Regarding Financial Statements or Accounting Policies: The Committee is to establish procedures for (A) the receipt, retention, and treatment of complaints received by the Company from employees regarding accounting, internal accounting controls, or auditing matters; and (B) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters as required by Section 301 of the Sarbanes-Oxley Act of 2002 and the rules and listing requirements promulgated thereunder by the SEC and the NYSE. The Committee is to discuss with management and the independent auditors any correspondence with regulators or governmental agencies and any complaints or concerns regarding the Company’s financial statements or accounting policies.

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18)

Discuss With General Counsel Matters Regarding Financial Statements or Compliance Policies: The Committee should discuss with the Company’s General Counsel legal matters that may have a material impact on the financial statements or the Company’s compliance policies.

19)

Review and Discuss Other Matters: The Committee should review and discuss such other matters that relate to the accounting, auditing and financial reporting practices and procedures of the Company as the Committee may, in its own discretion, deem desirable in connection with the review functions described above.

20)

Make Board Reports: The Committee should report its activities regularly to the Board of Directors in such manner and at such times as the Committee and the Board of Directors deem appropriate, but in no event less than once a year. Such report should include the Committee’s conclusions with respect to its assessment of the performance and independence of the independent auditors.

21)

Maintain Flexibility. The Committee, in carrying out its responsibilities, policies and procedures should remain flexible, in order to best react to changing conditions and circumstances.

Meetings

The Committee shall meet in person or telephonically at least quarterly, or more frequently as it may determine necessary, to comply with its responsibilities as set forth herein. The Chair of the Committee will, in consultation with the other members of the Committee, the Company’s independent auditors and the appropriate officers of the Company, establish the agenda for each Committee meeting. Any Committee member may submit items to be included on the agenda. Committee members may also raise subjects that are not on the agenda at any meeting. The Committee Chair or a majority of the Committee members may call a meeting of the Committee at any time. A majority of the number of Committee members selected by the Board will constitute a quorum for conducting business at a meeting of the Committee. The act of a majority of Committee members present at a Committee meeting at which quorum is in attendance will be the act of the Committee, unless a greater number is required by law, the Company’s certificate of incorporation or its by-laws. Any Committee member may be excused from a meeting to permit the remaining members of the Committee to act on any matter in which such member’s participation is not appropriate, and such member’s absence shall not destroy the quorum for the meeting. The Committee also may take action by unanimous written consent. The Committee Chair will supervise the conduct of the meetings and will have other responsibilities as the Committee may specify from time to time.

The Committee may request any officer or employee of the Company or any representative of the Company’s legal counsel or independent auditors or other advisors to attend a meeting of the Committee or to meet with any members, or representatives of the Committee. The Committee shall meet with the Company’s management, the internal auditors and the independent auditors periodically in separate private sessions to discuss any matter that the Committee, management, the independent auditors or such other persons believe should be discussed privately.

Resources and Authority

The Committee shall have appropriate resources and authority to discharge its responsibilities as required by law, including the authority to engage independent legal counsel and other advisors as the Committee deems necessary to carry out its responsibilities. The Committee may also, to the extent it deems necessary or appropriate, meet with the Company’s investment bankers or financial analysts who follow the Company.

The Company will provide for appropriate funding, as determined by the Committee, for payment of compensation (i) to the Company’s independent auditors engaged for the purpose of rendering or issuing an audit report or related work or performing other audit, review or attest services for the Company, and (ii) to independent counsel or any other advisors employed by the Committee.

Audit Committee Report

The Committee will prepare, with the assistance of management, the independent auditors and legal counsel, the Audit Committee Report.

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Annual Review

In 2004 and annually thereafter, the Committee shall (a) review this Charter with the Board and recommend any changes to the Board and (b) evaluate its performance against the requirements of this Charter and review this evaluation with the Board. The Committee shall conduct its review and evaluation in such manner as the Committee, in its business judgment, deems appropriate.

Consistent with New York Stock Exchange listing requirements, this Charter will be included on the Company’s website and will be made available upon request sent to the Company’s Corporate Secretary. The Company’s annual report to stockholders will state that this Charter is available on the Company’s website and will be available upon request sent to the Company’s Corporate Secretary.

March 2005

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OG&E

OGE Energy Corp.

2004 Management’s
Discussion and Analysis

Appendix A to the Proxy Statement

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 management of 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 and 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. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture margins across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates Ozark Gas Transmission, L.L.C. (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, was sold in 2002 and in the first quarter of 2003 and are reported in the Consolidated Financial Statements as discontinued operations.

Executive Overview

In early 2002, the Company completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, the Company recognized that immediate deregulation of the retail electric markets in Oklahoma and Arkansas was very unlikely and revised its business strategy. In the summer of 2004, the Company again reviewed its business strategy in light of significant changing market and regulatory trends such as the over supply of electric generation, the evolution of electric transmission markets and rules, the natural gas supply forecast, the sustained increase of natural gas commodity prices and the anticipated emergence of liquefied natural gas. The Company concluded that its existing business strategy of utilizing a diversified asset position was the proper course.

During 2004, the Company had several significant accomplishments including the completion of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the

“McClain Plant”) in July 2004, the completion of two revolving credit agreements totaling $550 million for the Company and OG&E in October 2004, improved financial performance at Enogex, improved financial flexibility associated with the reduction of the long-term debt balance at Enogex, such that Enogex began to contribute to funding the Company’s dividend which has been funded solely by OG&E in the past. Looking at 2005, OG&E expects to file a rate case during the second quarter of 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant and expects new approved rates to be in effect by January 2006. Also, during 2005, OG&E will work to advance its Customer Savings and Reliability Plan which provides for increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment and deploy newer technology that improves operational and environmental performance. Capacity payment savings from reduced cogeneration payments and fuel savings from the McClain Plant will be utilized to mitigate the price increases associated with these investments. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 18 of Notes to Consolidated Financial Statements. During 2005, the Company will also be focused on controlling and managing operating and maintenance expenses and will continue to analyze the cost structure of the Company’s businesses ensuring consistency with the Company’s business model. At Enogex during 2005, the Company will focus on enhancing its financial position and the operations of its mid-continent assets as well as seeking to expand into other geographic areas outside of the mid-continent area. Overall, the Company has a strong commitment to train and retain talented personnel so that both the Company and its employees are successful in improving the financial and operating performance of the Company.

The Company’s vision is to be a regional energy company focused on its regulated utility business and natural gas pipeline business that is recognized for operational excellence and financial performance. 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 normalized basis, a dividend payout ratio below 75 percent and an A- credit rating.

At Enogex, the Company 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. Enogex’s marketing business, which concentrates principally on origination of physical sales of natural gas, has expanded into the Gulf Coast, Rocky Mountain and East Coast markets.

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 focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as a vertically integrated utility engaged in the generation, transmission and distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s consolidated assets will be in Enogex’s businesses. At December 31, 2004, OG&E and Enogex represented approximately 63 percent and 36 percent, respectively, of the Company’s consolidated assets. The remaining one percent of the Company’s consolidated assets were primarily at the holding company. 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 subject to the

evolving federal regulations of the FERC in regard to the operations of the wholesale power market. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.

OG&E has approximately 430 MWs of contracts with qualified cogeneration facilities and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by OG&E. In addition, effective September 1, 2004, OG&E entered into a new 15-year power sales agreement for 120 MWs with PowerSmith Cogeneration Project, L.P. (“PowerSmith”). OG&E will continue reviewing all of the supply alternatives to these expiring 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. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units.

Enogex initiated a program in 2002 to improve its financial profile and performance. Since January 1, 2002, Enogex has completed significant sales transactions which have generated net sales proceeds of approximately $106.3 million, reduced debt by approximately $226.8 million or 30.6 percent, reduced its number of employees by approximately 12 percent, reorganized its operations and restructured its senior management team. In addition to focusing on growing its earnings, Enogex managed its commodity price and earnings volatility exposures and minimized its exposure to keep-whole processing arrangements. Enogex’s profitability increased significantly in 2003 and 2004 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.

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. Enogex’s marketing business, which concentrates principally on origination of physical sales of natural gas, has expanded into the Gulf Coast, Rocky Mountain and East Coast markets.

In addition to these ongoing efforts, in 2003 Enogex began a major upgrade of its information systems that is expected to be substantially completed during the second and third quarters of 2005. Enogex believes that these upgrades will be a major step towards obtaining the data required to allow it to capture available economic opportunities on its assets, provide improved customer service and enable management to better determine the earnings potential of its various assets and service offerings.

During 2004, Enogex made improvements to the Stuart Storage Facility which reduced water encroachment in the field. During 2004, approximately $1.9 million in capital expenditures was spent on this project. Enogex does not expect any material future expenditures on this water encroachment project.

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2005 Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; the Company’s ability and the ability of its subsidiaries to obtain financing on favorable terms; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; federal or state legislation and regulatory decisions (the proceeding currently pending before the OCC related to OG&E’s recovery of the costs billed to it by Enogex for gas transportation and storage services) and initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company’s markets; environmental laws and regulations that may impact the Company’s operations; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers and other contractual parties; the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission.

Overview

Summary of Operating Results

2004 compared to 2003. The Company reported net income of approximately $153.5 million, or $1.73 per diluted share, as compared to approximately $129.8 million, or $1.58 per diluted share, for the years ended December 31, 2004 and 2003, respectively. The increase in net income during 2004 as compared to 2003 was primarily due to:

higher gross margins on revenues (“gross margin”) in Enogex’s gathering and processing business primarily due to an overall favorable business environment coupled with higher commodity prices;

gains from asset sales; and

lower net interest expense.

These increases to net income were partially offset by:

lower gross margins at OG&E due to cooler weather in its service territory; and

higher operating expenses.

OG&E reported net income of approximately $107.6 million, or $1.22 per diluted share of the Company’s common stock, as compared to approximately $115.4 million, or $1.41 per diluted share, for the years ended December 31, 2004 and 2003, respectively. The decrease in net income at OG&E during 2004 as compared to 2003 is described in more detail below.

Enogex’s operations, including discontinued operations, reported net income of approximately $60.7 million, or $0.69 per diluted share of the Company’s common stock, as compared to approximately $26.9 million, or $0.33 per diluted share, for the years ended December 31, 2004 and 2003, respectively. The increase in net income at Enogex during 2004 as compared to 2003 is described in more detail below.

The results of the holding company reflect a loss of approximately $0.18 per diluted share and $0.16 per diluted share, respectively, for the years ended December 31, 2004 and 2003. The increased loss is primarily due to an increase in net interest expense due to a write off of approximately $5.9 million of unamortized debt issuance costs for the trust preferred securities which were redeemed at par on October 15, 2004, partially offset by an increase in other income.

The Company’s results of operations for the years ended December 31, 2004 and 2003, respectively, include income of approximately $0.5 million, or $0.01 per diluted share, and a loss of approximately $0.4 million, or less than $0.01 per diluted share, from the discontinued operations discussed below. See “Results of Operations – Enogex – Discontinued Operations” for a further discussion.

Earnings per share in 2004 as compared to 2003 were affected by a higher amount of common stock outstanding from the Company’s equity issuance in August 2003 and the issuance of common stock in 2003 and 2004 pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”).

2003 compared to 2002. The Company reported net income of approximately $129.8 million, or $1.58 per diluted share, as compared to approximately $90.8 million, or $1.16 per diluted share, for the years ended December 31, 2003 and 2002, respectively. The increase in net income during 2003 as compared to 2002 was primarily due to:

lower impairment charges at Enogex;

higher gross margins in all of Enogex’s businesses;

growth in OG&E’s service territory; and

lower interest expenses at the holding company.

These increases to net income were partially offset by:

lower gross margins at OG&E due to lower electric rates as a result of the $25 million electric reduction that went into effect in Oklahoma on January 6, 2003.

OG&E reported net income of approximately $115.4 million, or $1.41 per diluted share, as compared to approximately $126.1 million, or $1.61 per diluted share, for the years ended December 31, 2003 and 2002, respectively. The decrease in net income during 2003 as compared to 2002 is described in more detail below.

Enogex’s operations, including discontinued operations, reported net income of approximately $26.9 million, or $0.33 per diluted share, as compared to a net loss of approximately $21.7 million, or $0.28 per diluted share, for the years ended December 31, 2003 and 2002, respectively. This improvement during 2003 as compared to 2002 is described in more detail below.

The results of the holding company reflect a loss of approximately $0.16 per diluted share and $0.17 per diluted share for the years ended December 31, 2003 and 2002, respectively, primarily due to lower interest expenses and a higher income tax benefit partially offset by higher other miscellaneous expenses.

The Company’s results of operations for the years ended December 31, 2003 and 2002, respectively, include a loss of approximately $0.4 million, or less than $0.01 per diluted share, and income of approximately $9.8 million, or $0.12 per diluted share, from the discontinued operations discussed below. See “Results of Operations – Enogex – Discontinued Operations” for a further discussion.

Regulatory Matters and Plant Acquisition

In November 2002, the OCC issued an order containing provisions of an agreed-upon settlement of OG&E’s rate case. The terms of this settlement included, among other things, a $25.0 million annual reduction in electric rates and a requirement for OG&E to acquire 400 MWs of electric generation. The rate reduction went into effect January 6, 2003 and the acquisition of a 77 percent interest in the 520 MW McClain Plant was completed on July 9, 2004. The McClain Plant, located near Newcastle, Oklahoma, is a combined cycle unit consisting of two natural-gas fired combustion turbine generators combined with a steam turbine generator. The owner of the remaining 23 percent interest in the McClain Plant is the Oklahoma Municipal Power Authority. OG&E operates the plant. The purchase price was approximately $160.0 million. OG&E temporarily funded the McClain Plant acquisition with short-term borrowings from the Company. On August 4, 2004, OG&E issued $140.0 million of long-term debt to replace these short-term borrowings. Also, on August 9, 2004, the Company made a capital contribution to OG&E of approximately $153.0 million. For additional information regarding the McClain Plant acquisition and related regulatory matters, see Note 18 of Notes to Consolidated Financial Statements.

2005 Outlook

For 2005, the Company’s earnings guidance is $137 million to $147 million of net income, or $1.50 to $1.60 per share, assuming approximately 90.5 million average diluted shares outstanding. The 2005 outlook includes earnings guidance of $106 million to $110 million, or $1.17 to $1.22 per share, at OG&E and $39 million to $43 million, or $0.43 to $0.48 per share, at Enogex, while earnings guidance at the holding company is a loss between $6 million and $8 million, or $0.07 to $0.09 per share. During 2005, the Company expects cash flow from operations of between $323 million and $332 million. In 2005, OG&E plans to increase capital expenditures for electric system reliability upgrades. Additionally, funding for the Company’s pension plan is expected to be approximately $37.4 million in 2005. Expected 2005 net income assumes a 38.7 percent effective tax rate.

For 2005, OG&E earnings guidance is $106 million to $110 million, or $1.17 to $1.22 per share. OG&E assumes that margin growth approximating one to two percent will be more than offset by increased operating expenses and higher interest costs associated with the acquisition of the McClain Plant and capital expenditures for investment in OG&E’s generation, transmission and distribution system. OG&E expects to increase capital expenditures to approximately $248 million for electric system expansion and reliability upgrades in 2005. Key factors affecting OG&E’s 2005 net income will be the result of pending regulatory proceedings, weather, OG&E’s ability to control operating and maintenance expenses and customer growth. 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. The earnings guidance further assumes no change in base rates and normal weather. OG&E expects to file a rate case during the second quarter of 2005 to recover, among other things, its investment in, and the operating expenses of, the McClain Plant and expects new approved rates to be in effect by January 2006. The earnings guidance also assumes a recovery of the costs associated with the Enogex natural gas transportation and storage services at a level consistent with a recent recommendation by the administrative law judge overseeing this proceeding. On October 22, 2004, the administrative law judge overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with OG&E refunding to its customers any amounts collected in excess of this amount. If this recommendation is ultimately accepted, OG&E believes its refund obligation would be approximately $6.9 million at December 31, 2004, which the Company does not believe is material in light of previously established reserves. An OCC order in this case is expected in the first quarter of 2005. There can be no guarantee that the OCC will approve the $41.9 million annual demand fee recovery recommended by the administrative law judge. See Note 18 of Notes to Consolidated Financial Statements for a further discussion of this matter.

For 2005, Enogex earnings guidance is $39 million to $43 million, or $0.43 to $0.48 per share. Enogex manages its operations along three related businesses: transportation and storage; gathering and processing; and marketing. In 2005, these businesses are assumed to produce a gross margin of approximately $269 million, down from $301 million in 2004. The Company expects approximately 46 percent of Enogex’s gross margin during 2005 to be generated from its transportation and storage business as compared to 46 percent in 2004. Approximately 88 percent of these gross margins are under firm contracts. Revenues in transportation and storage are primarily from gas transportation contracts with utilities in Oklahoma and Arkansas and independent power producers (“IPP”) in Oklahoma. Revenues in the transportation and storage business are expected to decrease due to the completion in 2004 of the over recovery of prior year’s under recovered fuel. The Company expects its gathering and processing business to contribute approximately 48 percent of Enogex’s gross margin in 2005 as compared to 46 percent in 2004. Revenues in gathering and processing are expected to increase in 2005 primarily due to continued efforts to increase margins from the negotiation of both new contracts and replacement contracts. Volumes are expected to remain flat from 2004. The Company has assumed lower commodity spreads of $1.53 per Million British thermal unit (“MMBtu”) in 2005 as compared to $2.45 per MMBtu in 2004 and has assumed lower average natural gas liquids prices of $0.71 per gallon in 2005 as compared to $0.72 per gallon in 2004. The Company also assumes 242 new well connects in its gathering and processing business in 2005. While operating improvements allowed Enogex to capture significant value in a favorable commodity environment, the commodity and well connect assumptions budgeted for 2005 reflect commodity prices that are not as robust as those experienced in 2004. The Company expects its marketing business to contribute approximately six percent of Enogex’s gross margin in 2005 as compared to eight percent in 2004. Gross margins in marketing are expected to decrease in 2005 primarily due to 2004 gross margins being above expectations and its anticipated loss of approximately $3.0 million due to its position on the Cheyenne Plains Pipeline as explained in Note 17 of Notes to Consolidated Financial Statements. Enogex also expects approximately $5.1 million in lower operating expenses in 2005 due to not having an $8.6 million impairment charge that was recorded in the third quarter of 2004. In addition, Enogex also expects approximately $1.2 million in lower net interest expense from the retirement of long-term debt in 2004 and 2005. Key factors affecting Enogex’s 2005 net income will be new well connections, natural gas and natural gas liquids prices and operating costs. 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 determined or included in the 2005 earnings guidance.

For 2005, earnings guidance at the holding company, which primarily has interest expense but no operating revenue, is a loss between $6 million and $8 million, or $0.07 to $0.09 per share. The decrease in the loss as compared to 2004 is primarily due to lower interest expenses associated with the redemption of $200 million of trust preferred securities on October 15, 2004.

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 approximately 75 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. While the dividend payout ratio is expected to exceed the target payout ratio in 2005, management after considering estimates of future earnings and numerous other factors, expects at this time that it will continue to recommend to the Board of Directors a continuance of the current dividend rate.

Results of Operations

The following discussion and analysis presents factors which affected the Company’s consolidated results of operations for the years ended December 31, 2004, 2003 and 2002 and the Company’s consolidated financial position at December 31, 2004 and 2003. 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.

Enogex previously was engaged in the exploration and production of natural gas (the “E&P business”). Since January 1, 2002, Enogex has sold all of its E&P business along with certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”) and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the years ended December 31, 2004, 2003 and 2002 in the Consolidated Financial Statements.


(In millions, except per share data)		2004			2003			2002

Operating income	$	317.	5	$	306.	9	$	235.	7
Net income	$	153.	5	$	129.	8	$	90.	8
Basic average common shares outstanding		88.	0		81.	8		78.	1
Diluted average common shares outstanding		88.	5		82.	1		78.	2
Basic earnings per average common share	$	1.7	4	$	1.5	9	$	1.1	6
Diluted earnings per average common share	$	1.7	3	$	1.5	8	$	1.1	6
Dividends declared per share	$	1.3	3	$	1.3	3	$	1.3	3

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. Included in 2004, 2003 and 2002 operating income are pre-tax impairment charges of approximately $7.8 million, $10.2 million and $50.1 million, respectively. These

impairments, primarily for Enogex natural gas processing and compression assets that were no longer needed in Enogex’s business, were made in accordance with accounting principles generally accepted in the United States.

Operating Income (Loss) by Business Segment

(In millions)		2004			2003			2002

OG&E (Electric Utility)	$	192.	0	$	216.	2	$	239.	1
Enogex (Natural Gas Pipeline) (A)		126.	6 (B)		91.	2 (B)		(3.	0) (B)
Other Operations (C)		(1.	1)		(0.	5)		(0.	4)

Consolidated operating income	$	317	.5	$	306	.9	$	235	.7

(A) Excludes discontinued operations. See “Enogex - Discontinued Operations” for a further discussion.
(B) After recording pre-tax impairment charges of approximately $7.8 million, $9.2 million and $48.3 million 2004, 2003 and 2002, respectively.
(C) Other Operations primarily includes unallocated corporate expenses.

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

OG&E

(Dollars in millions)	2004			2003			2002
Operating revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0
Fuel		645	.4		544	.5		435	.8
Purchased power		269	.1		292	.9		260	.0

Gross margin on revenues		663	.6		679	.7		692	.2
Other operating and maintenance		301	.9		294	.8		282	.9
Depreciation		122	.7		121	.8		123	.1
Taxes other than income		47	.0		46	.9		47	.1

Operating income	$	192	.0	$	216	.2	$	239	.1

Operating revenues by classification Residential	$	611	.4	$	601	.4	$	557	.6
Commercial		389	.9		372	.5		346	.9
Industrial		326	.7		293	.4		258	.6
Public authorities		158	.5		146	.1		135	.5
Sales for resale		57	.0		57	.7		48	.2
Provision for refund on gas transportation and storage case		(6	.9)		-	--		-	--
Other		40	.7		41	.9		34	.9

System sales revenues		1,577	.3		1,513	.0		1,381	.7
Off-system sales revenues		0	.8		4	.1		6	.3

Total operating revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0

MWH (A) sales by classification (in millions) Residential		7	.9		8	.2		8	.0
Commercial		5	.7		5	.8		5	.8
Industrial		7	.0		6	.8		6	.6
Public authorities		2	.7		2	.7		2	.7
Sales for resale		1	.4		1	.5		1	.5

System sales		24	.7		25	.0		24	.6
Off-system sales		0	.1		0	.1		0	.3

Total sales		24	.8		25	.1		24	.9

Number of customers		735,0	08		725,4	70		718,5	13

Average cost of energy per KWH (B) - cents Fuel		2.8	87		2.4	54		1.8	97
Fuel and purchased power		3.4	36		3.1	28		2.6	14

Degree days (C) Heating
Actual		3,1	14		3,4	88		3,7	53
Normal		3,6	50		3,6	31		3,6	34
Cooling
Actual		1,8	39		1,8	98		1,8	47
Normal		1,9	11		1,9	11		1,9	11

(A)

Megawatt-hour.

(B)

Kilowatt-hour.

(C)

Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

2004 compared to 2003. OG&E’s operating income decreased approximately $24.2 million or 11.2 percent in 2004 as compared to 2003. The decrease in operating income was primarily attributable to:

lower gross margins due to cooler weather in OG&E’s service territory;

lower margins related to sales to wholesale customers;

the timing of fuel recoveries; and

higher operating expenses.

These decreases in operating income were partially offset by:

growth in OG&E’s service territory.

Gross margin, which is operating revenues less cost of goods sold, was approximately $663.6 million in 2004 as compared to approximately $679.7 million in 2003, a decrease of approximately $16.1 million or 2.4 percent. The gross margin decreased primarily due to:

cooler weather in OG&E’s service territory which reduced the gross margin by approximately $15.7 million;

lower margins related to sales to wholesale customers primarily resulting from reduced sales of power under a new wholesale contract with an existing customer which reduced the gross margin by approximately $3.2 million; and

the timing of fuel recoveries which decreased the gross margin by approximately $1.7 million.

These decreases in gross margin were partially offset by:

growth in OG&E’s service territory which increased the gross margin by approximately $4.9 million.

Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense was approximately $645.4 million in 2004 as compared to approximately $544.5 million in 2003, an increase of approximately $100.9 million or 18.5 percent. The increase was primarily due to an increase in the average cost of fuel per kwh, primarily due to higher natural gas prices despite lower mwh sales. 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 2004, OG&E’s fuel mix was 70 percent coal and 30 percent natural gas as compared to 77 percent coal and 23 percent natural gas in 2003. Though OG&E has a higher installed capability of generation from natural gas units of 59 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $269.1 million in 2004 as compared to approximately $292.9 million in 2003, a decrease of approximately $23.8 million or 8.1 percent. The decrease was primarily due to OG&E’s acquisition of the McClain Plant in July 2004 and the termination of power purchase contracts in December 2003 and August 2004.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma, Arkansas and the FERC, in each jurisdiction

the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to OG&E. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See Note 18 of Notes to Consolidated Financial Statements for a discussion of current proceedings at the OCC regarding OG&E’s gas transportation and storage contract with Enogex.

Other operating and maintenance expenses were approximately $301.9 million in 2004 as compared to approximately $294.8 million in 2003, an increase of approximately $7.1 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

increased outside services expense of approximately $17.9 million, primarily due to higher expenses for infrastructure projects in the fourth quarter of 2004, many of which were postponed from earlier in 2004;

increased materials and supplies expense of approximately $1.8 million; and

increased liability insurance expense of approximately $0.9 million due to increased insurance premiums.

These increases in other operating and maintenance expenses were partially offset by:

lower salaries and wages expense of approximately $6.8 million and lower pension and benefit expense of approximately $6.6 million primarily due to more projects on which the costs are capitalized and are not being expensed currently.

Depreciation expense was approximately $122.7 million in 2004 as compared to approximately $121.8 million in 2003, an increase of approximately $0.9 million or 0.7 percent, primarily due to a higher level of depreciable plant. Also, another factor affecting 2004 results was an overall increase of approximately $3.8 million in the reserves related to litigation.

2003 compared to 2002. OG&E’s operating income decreased approximately $22.9 million or 9.6 percent in 2003 as compared to 2002. The decrease in operating income was primarily attributable to:

lower electric rates as a result of the $25 million electric rate reduction that went into effect in Oklahoma on January 6, 2003;

weaker weather-related demand;

lower sales to other utilities and power marketers (“off-system sales”); and

higher other operating and maintenance expenses.

These decreases in operating income were partially offset by:

growth in OG&E’s service territory.

Gross margin was approximately $679.7 million in 2003 as compared to approximately $692.2 million in 2002, a decrease of approximately $12.5 million or 1.8 percent. The gross margin decreased primarily due to:

lower electric rates as a result of the $25 million electric rate reduction that went into effect in Oklahoma on January 6, 2003, which reduced the gross margin by approximately $24.8 million;

weaker weather-related demand which reduced the gross margin by approximately $2.0 million; and

lower off-system sales which reduced the gross margin by approximately $1.9 million as off-system sales can vary based upon the supply and demand needs on OG&E’s generation system and the market for off-system sales.

These decreases in gross margin were partially offset by:

growth in OG&E’s service territory which increased the gross margin by approximately $17.5 million.

Fuel expense was approximately $544.5 million in 2003 as compared to approximately $435.8 million in 2002, an increase of approximately $108.7 million or 24.9 percent. The increase was due to a 29.4 percent increase in the average cost of fuel per kwh, primarily due to higher natural gas prices and higher mwh sales. 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 2003, OG&E’s fuel mix was 77 percent coal and 23 percent natural gas. Purchased power costs were approximately $292.9 million in 2003 as compared to approximately $260.0 million in 2002, an increase of approximately $32.9 million or 12.7 percent. The increase was primarily due to approximately a 28.2 percent increase in the volume of energy purchased primarily due to economic purchases.

Other operating and maintenance expenses were approximately $294.8 million in 2003 as compared to approximately $282.9 million in 2002, an increase of approximately $11.9 million or 4.2 percent. The increase in other operating and maintenance expenses was primarily due to:

higher pension and benefit expenses of approximately $10.7 million due to the general upward trend in these costs; and

costs of approximately $5.4 million incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset as these 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses in 2002.

These increases in other operating and maintenance expenses were partially offset by:

lower uncollectibles expense of approximately $3.5 million due to improved collection efforts.

Depreciation expense was approximately $121.8 million in 2003 as compared to approximately $123.1 million in 2002, a decrease of approximately $1.3 million or 1.1 percent, primarily due to a change made in the depreciation rate of production plant in 2003 as required by the settlement of OG&E’s rate case in November 2002 (the “Settlement Agreement”).

Enogex – Continuing Operations

(Dollars in millions)		2004			2003			2002

Operating revenues	$	3,443.	9	$	2,327.	8	$	1,684.	0
Gas and electricity purchased for resale (A)		3,054.	3		2,019.	1		1,402.	1
Natural gas purchases - other		88.	6		55.	4		70.	5

Gross margin on revenues		301.	0		253.	3		211.	4
Other operating and maintenance		101.	5		91.	2		101.	1
Depreciation		47.	6		44.	2		49.	3
Impairment of assets		7.	8		9.	2		48.	3
Taxes other than income		17.	5		17.	5		15.	7

Operating income (loss)	$	126.	6	$	91.	2	$	(3.	0)

New well connects		27	7		23	2		16	6

Gathered volumes - TBtu/d (B)		1.0	1		0.9	9		1.0	6
Incremental transportation volumes - TBtu/d		0.5	1		0.4	4		0.4	9

Total throughput volumes - TBtu/d		1.5	2		1.4	3		1.5	5

Natural gas processed - Mmcf/d (C)		50	2		41	4		45	5

Natural gas liquids sold (keep whole) - million gallons		26	3		20	7		28	5
Natural gas liquids sold (POL and fixed-fee) - million gallons		1	6		1	8		2	2

Total natural gas liquids sold - million gallons		27	9		22	5		30	7

Average sales price per gallon	$	0.72	0	$	0.59	5	$	0.40	6

(A) OGE Energy Resources, Inc. (“OERI”) exited the power marketing business during the first quarter of 2004. (B) Trillion British thermal units per day. (C) Million cubic feet per day.

2004 compared to 2003. Enogex’s operating income in 2004 increased approximately $35.4 million or 38.8 percent as compared to 2003. The increase in operating income was primarily attributable to higher gross margins in Enogex’s gathering and processing business primarily due to an overall favorable business environment coupled with higher commodity prices and revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms. These increases were partially offset by higher operating expenses.

Enogex sold its interest in NuStar during the first quarter of 2003; accordingly this is reported as discontinued operations for the years ended December 31, 2004, 2003 and 2002 in the Consolidated Financial Statements. See “Enogex – Discontinued Operations” for a further discussion.

Transportation and storage contributed approximately $137.4 million of Enogex’s gross margin in 2004 as compared to approximately $138.1 million in 2003, a decrease of approximately $0.7 million or 0.5 percent. The gross margin decreased primarily due to:

certain contractual revenues recorded in transportation and storage in 2003 being recorded in gathering and processing in 2004 which reduced the gross margin by approximately $12.7 million;

mark-to-market timing losses on natural gas storage inventory which reduced the gross margin by approximately $3.7 million;

the Calpine Energy Services, L.P. (“Calpine Energy”) settlement in 2003 which resulted in a one-time increase of approximately $2.0 million to the gross margin in 2003;

the net change between fuel retained and fuel consumed which decreased the gross margin by approximately $1.7 million; and

third party pipeline imbalances which decreased the gross margin by approximately $1.0 million.

These decreases in the transportation and storage gross margin were partially offset by:

higher purchases and sales activity due to Enogex being more active in the marketplace which increased the gross margin by approximately $6.6 million;

higher interruptible revenues and higher crosshaul revenues due to an increase in interruptible contract volumes and increased crosshaul margins and volumes which increased the gross margin by approximately $6.3 million;

higher transportation and storage revenues in 2004 primarily due to the additional demand fees and overrun charges from the transportation and storage contract with OG&E, which was effective May 2003, which increased the gross margin by approximately $4.9 million; and

an amended intercompany natural gas purchase contract which increased the gross margin by approximately $2.5 million.

Gathering and processing contributed approximately $139.8 million of Enogex’s gross margin in 2004 as compared to approximately $91.3 million in 2003, an increase of approximately $48.5 million or 53.1 percent. Gathering gross margins increased approximately $27.5 million in 2004 as compared to 2003 primarily due to:

the change in 2004 discussed above of recording certain contractual revenues in gathering and processing rather than in transportation and storage, which increased the gross margin by approximately $12.7 million;

revenue improvements generated from an overall favorable business environment coupled with higher commodity prices and the negotiation of both new contracts and replacement contracts at better terms; and

an increase in the number of well connects and the volumes of natural gas gathered.

Processing gross margins increased approximately $21.0 million in 2004 as compared to 2003 primarily due to:

increased keep-whole, percent of liquids and condensate margins due to favorable commodity prices and higher keep-whole volumes which increased the gross margin by approximately $21.9 million; and

an expense reallocation of compressor fuel (from processing in 2003 to transportation and storage in 2004) which increased the gross margin by approximately $1.3 million.

Marketing contributed approximately $23.8 million of Enogex’s gross margin in 2004 as compared to approximately $23.9 million in 2003, a decrease of approximately $0.1 million or 0.4 percent. The gross margin decreased primarily due to:

lower gains from the sale of natural gas in storage in 2004 of approximately $12.1 million primarily due to Enogex recording approximately a $9.0 million pre-tax loss as a cumulative effect of a change in accounting principle in the first quarter of 2003 rather

than recording this loss as a reduction of the gross margin. The cumulative effect of a change in accounting principle was the result of accounting for certain energy contracts and natural gas in storage at the lower of cost or market rather than on a mark-to-market basis (see Note 2 of Notes to Consolidated Financial Statements for a further discussion);

mark-to-market timing losses on natural gas storage inventory due to different pricing environments during 2004 as compared to 2003 which reduced the gross margin by approximately $2.2 million; and

exiting the power marketing business in 2004 which reduced the gross margin by approximately $1.1 million.

These decreases in the marketing gross margin were partially offset by:

new business activity in the marketing portfolio which increased the gross margin by approximately $12.2 million; and

lower demand fees expense for storage services due to establishing new rates for the new storage season which began April 1 which increased the gross margin by approximately $3.4 million.

Enogex’s other operating and maintenance expenses were approximately $101.5 million in 2004 as compared to approximately $91.2 million in 2003, an increase of approximately $10.3 million or 11.3 percent. The increase in other operating and maintenance expenses was primarily due to:

higher payroll, benefit and pension expenses of approximately $4.1 million due to hiring new employees, payment of overtime and salary increases;

higher outside service costs of approximately $2.4 million related to work performed to maintain the integrity and safety of Enogex’s pipeline;

higher materials and supplies expense of approximately $2.3 million for repairs and maintenance of systems; and

higher uncollectibles expense of approximately $1.4 million due to miscellaneous accounts receivable items becoming over 180 days old.

Depreciation expense was approximately $47.6 million in 2004 as compared to approximately $44.2 million in 2003, an increase of approximately $3.4 million or 7.7 percent. The increase was primarily due to a higher level of depreciable plant as the implementation of an information system was completed during the second quarter of 2004 in addition to accelerated depreciation recorded during the fourth quarter of 2004 related to the impairment involving four of Enogex’s non-contiguous pipeline asset segments.

Impairment of assets was approximately $7.8 million in 2004 as compared to approximately $9.2 million in 2003, a decrease of approximately $1.4 million or 15.2 percent. During September 2004, Enogex received notification from a customer that a transportation agreement involving four of Enogex’s non-contiguous pipeline asset segments located in West Texas and used to serve the customer’s power plants would be terminated effective December 31, 2004. In connection with the preparation of the third quarter 2004 financial statements, Enogex performed an evaluation on these assets and concluded that an impairment charge needed to be recorded. The primary reason for this determination was that these four pipeline asset segments were originally built for the specific purpose of providing gas transmission service to this customers’ four power plants that have been or are in the

process of being shut down, and, as a result, other alternative commercial uses for these facilities are considered unlikely. Also, in 2004, the Company reclassified several compressors and processing plants that were previously classified as assets held for sale to assets held and used. This decision was based on the fact these assets are no longer being marketed and the Company believes the value of the future benefit of holding these assets exceeds the current fair market value. As a result, in accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long–Lived Assets,” the Company determined the fair value of these assets based on a third party valuation of the assets and, as a result, the Company recorded a net gain of approximately $0.8 million during 2004 related to reclassifying these assets from assets held for sale to assets held and used, which was recorded as a credit to Impairment of Assets on the Consolidated Statements of Income. During 2003, an evaluation of the horsepower of compression needed to meet the operational requirements of the Company’s gathering and transmission system was performed based on the then current market conditions. The review identified compressor equipment that could be removed from the system and a pre-tax impairment loss of approximately $9.2 million was recorded in the fourth quarter of 2003 to recognize the difference between the carrying value of these units and their fair value expected to be realized in a disposal. The impairment recorded in the fourth quarter of 2003 resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows.

During the year ended December 31, 2004, Enogex had an increase in net income of approximately $4.9 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:

authorized recovery of previously under recovered fuel of approximately $3.8 million;

a gain on the sale of Enogex compression and processing assets of approximately $1.8 million;

an imbalance settlement with a customer of approximately $1.6 million;

a net Oklahoma investment tax credit of approximately $1.5 million;

a settlement related to a customer bankruptcy of approximately $0.5 million; and

income from discontinued operations of approximately $0.5 million.

These increases to net income were partially offset by:

a net impairment charge of approximately $4.8 million.

During the year ended December 31, 2003, Enogex had an increase in net income of approximately $3.6 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:

authorized recovery of previously under recovered fuel of approximately $6.5 million;

a gain on the sale of assets of approximately $2.6 million;

a settlement related to a dispute with Calpine Energy of approximately $1.2 million; and

a pricing adjustment on a processing contract with a customer of approximately $1.1 million.

These increases to net income were partially offset by:

an impairment charge of approximately $5.7 million;

an income tax adjustment of approximately $1.7 million; and

a loss from discontinued operations of approximately $0.4 million.

2003 compared to 2002. Enogex’s operating income in 2003 increased approximately $94.2 million as compared to 2002. The increase in operating income was primarily attributable to:

lower impairment charges;

higher gross margins in all of Enogex’s businesses, from among other things, improved management of pipeline system fuel, increased levels of firm transportation revenues, improved processing results and the negotiation of both new contracts and replacement contracts at better terms; and

lower operating and maintenance expenses.

Enogex sold its E&P business and its interest in Belvan during 2002 and Enogex sold its interest in NuStar during the first quarter of 2003; accordingly, these are reported as discontinued operations for the years ended December 31, 2003 and 2002 in the Consolidated Financial Statements. See “Enogex – Discontinued Operations” for a further discussion.

Transportation and storage contributed approximately $138.1 million of Enogex’s gross margin in 2003 as compared to approximately $120.8 million in 2002, an increase of approximately $17.3 million or 14.3 percent. The gross margin increased primarily due to:

improved management of pipeline system fuel which, when coupled with higher natural gas prices, accelerated the authorized recovery of pipeline system fuel expense, which was the result of Enogex under recovering fuel in prior periods which increased the gross margin by approximately $11.8 million;

higher storage revenues primarily due to new demand fees from the contract with OG&E related to the purchase of the Stuart Storage Facility in August 2002 and increased demand fees from both third parties and Enogex’s marketing business which increased the gross margin by approximately $8.8 million; and

higher levels of firm transportation revenues as a result of the Calpine Energy settlement and an increase in related demand fees recognized in 2003 which collectively increased the gross margin by approximately $5.7 million.

These increases in the transportation and storage gross margin were partially offset by:

lower interruptible revenues related to bundled contracts due to a revenue reallocation (from Enogex’s transportation and storage business to Enogex’s gathering and processing business) to more accurately reflect the performance of Enogex’ businesses which reduced the gross margin by approximately $2.8 million;

higher electric compression costs which reduced the gross margin by approximately $1.2 million; and

an imbalance collectibility reserve which reduced the gross margin by approximately $1.2 million.

Gathering and processing contributed approximately $91.3 million of Enogex’s gross margin in 2003 as compared to approximately $73.0 million in 2002, an increase of approximately $18.3 million or 25.1 percent. Gathering gross margins increased approximately $9.8 million in 2003 as compared to 2002 primarily due to:

higher interruptible revenues related to bundled contracts due to a revenue reallocation related to bundled contracts (from Enogex’s transportation and storage business to Enogex’s gathering and processing business) to more accurately reflect the performance of Enogex’s businesses which increased the gross margin by approximately $2.8 million;

revenue improvements generated from the negotiation of both new contracts and replacement contracts at better terms; and

an increase in the number of well connects.

Processing gross margins increased approximately $8.5 million in 2003 as compared to 2002 primarily due to:

wider commodity spreads between natural gas and natural gas liquids; and

better management and dispatch of the plants; however, processing volumes were lower as a result of economic dispatching of the network of processing plants based upon market conditions.

Marketing contributed approximately $23.9 million of Enogex’s gross margin in 2003 as compared to approximately $17.6 million in 2002, an increase of approximately $6.3 million or 35.8 percent. The gross margin increased primarily due to:

higher gains from the sale of natural gas in storage in 2003 of approximately $10.2 million primarily due to Enogex recording approximately a $9.0 million pre-tax loss as a cumulative effect of a change in accounting principle in the first quarter of 2003 rather than recording this loss as a reduction of the gross margin. The cumulative effect of a change in accounting principle was the result of accounting for certain energy contracts and natural gas in storage at the lower of cost or market rather than on a mark-to-market basis (see Note 2 of Notes to Consolidated Financial Statements for a further discussion).

This increase in the marketing gross margin was partially offset by:

higher demand fees expense paid to Enogex’s transportation and storage business which reduced the gross margin by approximately $2.2 million; and

a change in the timing of revenue recognition related to natural gas in storage under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, in 2003 as compared to mark-to-market accounting in 2002 which reduced the gross margin by approximately $0.9 million. This accounting change was driven by the rescission of mark-to-market accounting for natural gas in storage as a result of Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which was issued in October 2002 (see Note 2 of Notes to Consolidated Financial Statements for a further discussion).

Enogex’s other operating and maintenance expenses were approximately $91.2 million in 2003 as compared to approximately $101.1 million in 2002, a decrease of approximately $9.9 million or 9.8 percent. The decrease in other operating and maintenance expenses was primarily due to:

lower uncollectibles expense of approximately $4.9 million due to establishing reserves in 2002 related to two customer bankruptcies;

lower materials and supplies expense of approximately $4.2 million due to the active use of inventories;

lower expense allocations from the parent of approximately $1.6 million due to the closing of two natural gas processing plants in 2003; and

lower miscellaneous operating expenses in 2003 due to termination benefits of approximately $0.9 million.

These decreases in other operating and maintenance expenses were partially offset by:

higher outside service costs of approximately $2.0 million related to work performed to maintain the integrity and safety of Enogex’s pipeline as well as the cost of new well connects.

Depreciation expense was approximately $44.2 million in 2003 as compared to approximately $49.3 million in 2002, a decrease of approximately $5.1 million or 10.3 percent. The decrease was primarily the result of ceasing depreciation on the assets written down as of December 31, 2002 due to the Company’s decision to sell these assets and classify them as held for sale in the fourth quarter of 2002.

Impairment charges were approximately $9.2 million in 2003 as compared to approximately $48.3 million in 2002, a decrease of approximately $39.1 million or 81.0 percent. The impairment charges in 2003 and 2002 related to certain idle Enogex natural gas compression assets.

Taxes other than income were approximately $17.5 million in 2003 as compared to approximately $15.7 million in 2002, an increase of approximately $1.8 million or 11.5 percent. The increase was the result of higher ad valorem taxes.

authorized recovery of previously under recovered fuel of approximately $6.5 million;

a gain on the sale of assets of approximately $2.6 million;

a settlement related to a dispute with Calpine Energy of approximately $1.2 million; and

a pricing adjustment on a processing contract with a customer of approximately $1.1 million.

These increases to net income were partially offset by:

an impairment charge of approximately $5.7 million;

an income tax adjustment of approximately $1.7 million; and

a loss from discontinued operations of approximately $0.4 million.

During the year ended December 31, 2002, Enogex had a decrease in net income of approximately $26.4 million relating to various items that the Company does not consider to be reflective of the ongoing profitability of Enogex’s business. The decrease in net income includes:

an impairment charge of approximately $31.1 million;

a reserve for two customer bankruptcies of approximately $2.8 million; and

a reserve for unpaid demand fees related to a dispute with Calpine Energy of approximately $2.3 million.

These decreases to net income were partially offset by:

income from discontinued operations of approximately $9.8 million.

Consolidated Other Income and Expense, Interest Expense and Income Tax Expense

2004 compared to 2003. Other income includes, among other things, contract work performed by OG&E, non-operating rental income, gain on the sale of assets, minority interest income and miscellaneous non-operating income. Other income was approximately $12.1 million in 2004 as compared to approximately $8.1 million in 2003, an increase of approximately $4.0 million or 49.4 percent. The increase in other income was primarily due to:

a realized gain of approximately $3.2 million from the sale of OG&E’s interests in its natural gas producing properties;

a realized gain of approximately $3.0 million on the sale of certain of Enogex’s compression and processing assets;

appreciation of investments associated with certain participants’ contributions in the deferred compensation plan and restoration of retirement income plan of approximately $1.0 million;

increased allowance for equity funds used during construction in 2004 of approximately $0.9 million;

a bankruptcy settlement from one of the Company’s customers of approximately $0.8 million;

a realized gain of approximately $0.6 million from the repurchase of outstanding heat pump loans; and

a realized gain of approximately $0.3 million from the sale of land and buildings near the Company’s principal executive offices.

These increases in other income were partially offset by:

a realized gain of approximately $5.3 million related to the sale of approximately 29 miles of transmission lines of the Ozark pipeline in the first quarter of 2003.

Other expense includes, among other things, expenses from the losses on the sale of assets, minority interest expense, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense was approximately $5.5 million in 2004 as compared to approximately $9.0 million in 2003, a decrease of approximately $3.5 million or 38.9 percent. The decrease in other expense was primarily due to:

realized losses of approximately $1.3 million from the sale of miscellaneous assets in 2003;

minority interest expense of approximately $1.1 million in the first quarter of 2003 related to the gain from the sale of approximately 29 miles of transmission lines of the Ozark pipeline that was attributable to the minority interest; and

a loss from the dissolution of a lease in the third quarter of 2003 of approximately $0.7 million.

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $90.9 million in 2004 as compared to approximately $96.7 million in 2003, a decrease of approximately $5.8 million or 6.0 percent. The decrease in net interest expense was primarily due to:

a reduction in interest expense of approximately $5.0 million due to the reduction and early retirement of long-term debt;

an increase in interest income of approximately $3.6 million due to the interest portion of an income tax refund related to prior periods;

a reduction in interest expense and commercial paper service fees of approximately $1.6 million due to the Company having a lower average commercial paper balance outstanding in 2004 as compared to 2003; and

a reduction in interest expense of approximately $1.1 million due to an increase in the allowance for borrowed funds used during construction.

These decreases in net interest expense were partially offset by:

an increase in interest expense of approximately $5.9 million due to the write off of unamortized debt issuance costs for the trust preferred securities; and

an increase in interest expense of approximately $0.7 million due to the issuance of long-term debt in November 2004.

Income tax expense was approximately $80.2 million in 2004 as compared to approximately $73.7 million in 2003, an increase of approximately $6.5 million or 8.8 percent. The increase in income tax expense was primarily due to:

higher pre-tax income for Enogex.

This increase in income tax expense was partially offset by:

lower pre-tax income for OG&E; and

the recognition of additional Oklahoma state tax credits of approximately $4.1 million during 2004.

2003 compared to 2002. Other income was approximately $8.1 million in 2003 as compared to approximately $3.7 million in 2002, an increase of approximately $4.4 million. The increase in other income was primarily due to:

a realized gain of approximately $5.3 million related to the sale of approximately 29 miles of transmission lines of the Ozark pipeline in the first quarter of 2003.

This increase in other income was partially offset by:

lower appreciation of investments in 2003 as compared to 2002 associated with certain participants’ contributions in the deferred compensation plan of approximately $0.9 million.

Other expense was approximately $9.0 million in 2003 as compared to approximately $4.7 million in 2002, an increase of approximately $4.3 million or 91.5 percent. The increase in other expense was primarily due to:

an increased liability associated with the deferred compensation plan approximately a $1.0 million;

a loss on the retirement of fixed assets of approximately $0.9 million;

a loss from the dissolution of a lease in the third quarter of 2003 of approximately $0.7 million; and

a loss from the sale of the Company’s aircraft in the third quarter of 2003 of approximately $0.1 million.

Net interest expense was approximately $96.7 million in 2003 as compared to approximately $109.1 million in 2002, a decrease of approximately $12.4 million or 11.4 percent. The decrease in net interest expense was primarily due to:

a reduction in interest expense of approximately $7.9 million related to the retirement of $140.0 million of Enogex debt during 2002;

a reduction in interest expense of approximately $2.5 million due to a lower average commercial paper balance in 2003 as compared to 2002; and

a reduction in interest expense of approximately $2.3 million related to lower interest rates on outstanding debt achieved from entering into interest rate swap agreements.

Income tax expense was approximately $73.7 million in 2003 as compared to approximately $44.6 million in 2002, an increase of approximately $29.1 million or 65.2 percent. The increase in income tax expense was primarily due to:

higher pre-tax income for Enogex.

This increase in income tax expense was partially offset by:

lower pre-tax income for OG&E;

a greater deduction for the Company’s Employee Stock Ownership Plan dividends in 2003, which reduced taxable income as compared to 2002;

a reversal of previously accrued federal income tax in 2002 related to several issues that were resolved in favor of the Company; and

an Oklahoma income tax refund in 2002 related to Oklahoma investment tax credits from prior years.

Enogex – Discontinued Operations

Enogex sold its interests in Belvan for approximately $9.8 million in March 2002. The Company recognized an after tax gain of approximately $1.6 million related to the sale of these assets.

Enogex sold its exploration and production assets located in Oklahoma, Texas, Arkansas and Mississippi for approximately $15.0 million in August 2002. The Company recognized an after tax gain of approximately $2.3 million related to the sale of these assets.

Enogex sold its exploration and production assets located in Michigan for approximately $32.0 million in November 2002. The Company recognized an after tax gain of approximately $2.9 million related to the sale of these assets.

Enogex sold its interests in NuStar for approximately $37.0 million in February 2003. The Company recognized an after tax gain of approximately $1.4 million related to the sale of these assets in the first quarter of 2003. Following completion of the final accounting for the NuStar sale, the Company recorded an additional charge of approximately $0.2 million after tax in the third quarter of 2003. The final accounting is subject to approval by all parties to the sale of the joint venture interest. During 2004, the Company recognized approximately $0.5 million after tax from funds received related to an overpayment for natural gas purchases in a prior period.

As a result of these sale transactions, Enogex’s E&P business, its interest in NuStar and its interest in Belvan, all of which were part of the Natural Gas Pipeline segment, have been reported as discontinued operations for the years ended December 31, 2004, 2003 and 2002 in the Consolidated Financial Statements. Results for these discontinued operations are summarized and discussed below.

(In millions)		2004			2003			2002

Operating revenues	$	0	.8	$	7	.8	$	79	.5
Gas purchased for resale		-	--		5	.9		49	.5
Natural gas purchases - other		-	--		0	.6		6	.4

Gross margin on revenues		0	.8		1	.3		23	.6
Other operation and maintenance		-	--		1	.1		12	.1
Depreciation		-	--		0	.2		4	.4
Taxes other than income		-	--		0	.1		0	.6

Operating income (loss)		0	.8		(0	.1)		6	.5

Other income		-	--		1	.9		1	.8
Net interest income		-	--		-	--		0	.1
Income tax expense (benefit)		0	.3		2	.2		(1	.4)

Net income (loss)	$	0	.5	$	(0	.4)	$	9	.8

2004 compared to 2003. Following the sale of NuStar in February 2003, no operations of NuStar are reflected in the Consolidated Financial Statements except for approximately $0.8 million received during 2004 related to an overpayment of natural gas purchases in a prior period.

2003 compared to 2002. Gross margin decreased approximately $22.3 million or 94.5 percent in 2003 as compared to 2002. Other operating and maintenance expenses decreased approximately $11.0 million or 90.9 percent, depreciation expense decreased $4.2 million or 95.5 percent and taxes other than income decreased approximately $0.5 million or 83.3 percent in 2003 as compared to 2002. The decreases in the gross margin, other operating and maintenance expenses, depreciation expense

and taxes other than income were attributable to the sale of Enogex’s E&P business and Belvan during 2002 and the sale of NuStar in February 2003.

Financial Condition

The balance of Cash and Cash Equivalents was approximately $26.4 million and $245.6 million at December 31, 2004 and 2003, respectively, a decrease of approximately $219.2 million or 89.3 percent. The balance at December 31, 2003 was primarily due to an increase in short-term investments at December 31, 2003 in anticipation of the need for funds to purchase the McClain Plant, which was originally expected to occur by December 31, 2003, and, which was ultimately completed on July 9, 2004.

The balance of Accounts Receivable was approximately $487.9 million and $350.2 million at December 31, 2004 and 2003, respectively, an increase of approximately $137.7 million or 39.3 percent. The increase was primarily due to higher natural gas prices and volumes associated with Enogex’s activities in the fourth quarter of 2004 partially offset by improved collection efforts at OG&E.

The balance of Fuel Inventories was approximately $89.0 million and $149.6 million at December 31, 2004 and 2003, respectively, a decrease of approximately $60.6 million or 40.5 percent. The decrease was primarily due to inventory sales at Enogex during 2004.

The balance of current Price Risk Management assets was approximately $118.6 million and $61.3 million at December 31, 2004 and 2003, respectively, an increase of approximately $57.3 million or 93.5 percent. The increase was primarily due to an increase in park and loan transactions, natural gas storage injections and withdrawals and related financial contracts associated with OERI’s activities during 2004.

The balance of the Gas Imbalance asset was approximately $100.1 million and $70.0 million at December 31, 2004 and 2003, respectively, an increase of approximately $30.1 million or 43.0 percent. The Gas Imbalance asset is comprised of planned or managed imbalances related to Enogex’s marketing 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 $76.0 million and $45.4 million at December 31, 2004 and 2003, respectively, an increase of approximately $30.6 million or 67.4 percent. The increase was due to an increase in park and loan transactions during 2004 resulting from economic opportunities in the marketplace.

The balance of Fuel Clause Under Recoveries was approximately $54.3 million at December 31, 2004. The balance of Fuel Clause Over Recoveries (net of Fuel Clause Under Recoveries) was approximately $28.4 million at December 31, 2003. The increase in fuel clause under recoveries was due to under recoveries from OG&E’s customers as OG&E’s cost of fuel exceeded the amount billed during 2004. The cost of fuel subject to recovery through the fuel clause mechanism was approximately $2.43 per MMBtu in December 2004, and was approximately $1.21 per MMBtu in December 2003. OG&E’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, OG&E 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 allow OG&E to amortize under or over recovery. OG&E expects to recover the fuel clause under recoveries during 2005.

The balance of Recoverable Take or Pay Gas Charges was approximately $17.0 million and $32.5 million at December 31, 2004 and 2003, respectively, a decrease of approximately $15.5 million or 47.7 percent. Approximately $21.0 million and $32.5 million have been recorded at December 31, 2004 and 2003, respectively, in the Provision for Payments of Take or Pay Gas classified as Current Liabilities and Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. These amounts represent OG&E’s estimate of the maximum amount that it could be obligated to pay under certain take-or-pay contracts. OG&E believes that it is entitled to recover any such amounts from its customers through its regulatorily approved automatic fuel adjustment clauses or other regulatory mechanisms.

The balance of Prepaid Benefit Obligation was approximately $92.7 million and $55.7 million at December 31, 2004 and 2003, respectively, an increase of approximately $37.0 million or 66.4 percent. The increase was primarily due to the Company funding its pension plan during the second and third quarters of 2004 partially offset by pension accruals being credited to the prepaid benefit obligation.

The balance of Short-Term Debt was approximately $125.0 million and $202.5 million at December 31, 2004 and 2003, respectively, a decrease of approximately $77.5 million or 38.3 percent. The balance at December 31, 2003 was primarily due to the incurrence of short-term debt in anticipation of the expected 2003 year-end closing of the acquisition of the McClain Plant, which was ultimately completed on July 9, 2004. In conjunction with the acquisition of the McClain Plant, the Company issued short-term debt to fund a portion of the acquisition, and, as a result, the short-term debt balance was approximately $216.1 million at July 31, 2004. On August 4, 2004, OG&E issued $140.0 million of long-term debt to replace these short-term borrowings. During October 2004, the Company issued approximately $170.0 million in commercial paper related to the redemption of the trust preferred securities, of which approximately $100.0 million was refinanced in November 2004 by the issuance of long-term debt.

The balance of Accounts Payable was approximately $476.2 million and $280.2 million at December 31, 2004 and 2003, respectively, an increase of approximately $196.0 million or 70.0 percent. The increase was primarily due to higher natural gas prices and volumes associated with Enogex’s activities in the fourth quarter of 2004.

The balance of current Price Risk Management liabilities was approximately $102.9 million and $46.9 million at December 31, 2004 and 2003, respectively, an increase of approximately $56.0 million. The increase was primarily due to an increase in park and loan transactions, natural gas storage injections and withdrawals and related financial contracts associated with OERI’s activities during 2004.

The balance of Long-Term Debt was approximately $1.42 billion and $1.44 billion at December 31, 2004 and 2003, respectively, a decrease of approximately $20 million or 1.4 percent. The decrease was primarily due to long-term debt maturities and the early retirement of long-term debt during 2004. These decreases were partially offset by the issuance of $140.0 million of long-term debt in August 2004 by OG&E to replace the short-term borrowings initially issued to finance the McClain Plant acquisition in addition to the issuance of $100.0 million of long-term debt in November 2004 related to the redemption of the trust preferred securities in October 2004.

The balance of Accrued Pension and Benefit Obligations was approximately $197.0 million and $167.4 million at December 31, 2004 and 2003, respectively, an increase of approximately $29.6

million or 17.7 percent. The increase was primarily due to an increase in the liability associated with the Company’s pension plan due to a decrease in the assumed discount rate. See Note 15 of Notes to Consolidated Financial Statements for a further discussion.

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

Heat Pump Loans

Prior to January 1, 2004, OG&E had a heat pump loan program that allowed qualifying customers to obtain a loan from OG&E to purchase a heat pump. In October 1998, OG&E sold approximately $25.0 million of its heat pump loans in a securitization transaction through OGE Consumer Loan LLC. During the second quarter of 2004, OG&E repurchased the outstanding heat pump loan balance of approximately $0.1 million. OG&E recorded a gain of approximately $0.6 million in the third quarter of 2004 related to this transaction. Effective November 19, 2004, the Company dissolved OGE Consumer Loan LLC. In November 1999, OG&E sold approximately $12.7 million of its heat pump loans in a securitization transaction through OGE Consumer Loan II LLC. In October 2004, OG&E repurchased the outstanding heat pump loan balance of approximately $1.1 million. OG&E recorded a loss of less than $0.1 million in the fourth quarter of 2004 related to this transaction. Effective January 31, 2005, the Company dissolved OGE Consumer Loan II LLC. Effective January 1, 2004, OG&E discontinued issuing heat pump loans to customers and all new heat pump loans are now processed and managed by a third party. OG&E continues to service the heat pump loans it recently repurchased in 2004 in addition to the heat pump loans OG&E sold during 2003. The finance rate on the heat pump loans was based upon market rates and was reviewed and updated periodically. The interest rate was 11.55 percent at December 31, 2003. OG&E’s heat pump loan balance was approximately $1.3 million and $1.4 million at December 31, 2004 and 2003, respectively and is included in Accounts Receivable, Net in the Consolidated Balance Sheets.

OG&E sold approximately $8.5 million of its heat pump loans in December 2002 as part of a securitization transaction through OGE Consumer Loan 2002, LLC. The following table contains information related to this securitization.


	2002

Date heat pump loans sold	December 2002
Total amount of heat pump loans sold (in millions)	$	8.5
Heat pump loan balance at December 31, 2004 (in millions)	$	3.9
Note interest rate		5.25%
Base servicing fee rate (paid monthly)		0.375%
Trustee/custodian fees (paid quarterly) (in whole dollars)	$	1,250
Owner trustee fees (paid annually) (in whole dollars)	$	4,000
Sole director’s fee (paid quarterly) (in whole dollars)	$	1,125
Loss exposure by securitization issue (in millions)	$	0.6

Energy Insurance Bermuda Ltd. Mutual Business Program No. 19

Energy Insurance Bermuda Ltd. (“EIB”) is incorporated in Bermuda under the Companies Act of 1981, as amended. The Company began participating in EIB through Mutual Business Program No. 19 (“MBP 19”) on November 15, 1998. The Company is the sole participant in MBP 19. In August 2002, the Company issued a $5.0 million standby letter of credit to MBP 19 for the benefit of insuring parts of the Company’s property and liability insurance programs. In June 2003, the standby letter of credit was increased to $8.0 million. MBP 19 was established to provide $15.0 million worth of property and liability insurance for the Company. The letter of credit was issued to provide protection for MBP 19 in the event of large insurance claim losses. At December 31, 2003, there were no drawings against this letter of credit. Because a letter of credit was issued, the total equity investment at risk of MBP 19 was not deemed sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, MBP 19 was considered a variable interest entity (“VIE”) as defined in Interpretation No. 46 and the Company was the primary beneficiary which resulted in the consolidation of MBP 19 into the Company’s Consolidated Financial Statements for the year ended December 31, 2003. Effective January 1, 2004, the reinsurer of the MBP 19 program agreed to remove the guarantee requirement which enabled the Company to terminate the standby letter of credit previously provided. However, the reinsurer added a ratings trigger requirement in the revised agreement such that if the commercial paper rating of the Company is lowered by two grades, MBP 19 may be surcharged an additional premium, which may result in an additional premium to the Company. Because the guarantee requirement was removed, the total equity investment at risk of MBP 19 was deemed sufficient to permit it to finance its activities without additional subordinated financial support from other parties. Therefore, effective January 1, 2004, MBP 19 was not considered a VIE as defined in Interpretation No. 46 which resulted in the deconsolidation of MBP 19 during the first quarter of 2004. The Company plans to terminate the MBP 19 program during the first quarter of 2005 and does not expect the impact of terminating this program to have a material effect on the Company’s consolidated financial position or results of operations.

OG&E Railcar Leases

At December 31, 2004, OG&E has a noncancellable operating lease which has purchase options covering 1,464 coal hopper railcars to transport coal from Wyoming to OG&E’s coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E’s tariffs and automatic fuel adjustment clauses. At the end of the lease term which is March 31, 2006, OG&E has the option to purchase the railcars at a stipulated fair market value. If OG&E chose not to purchase the railcars and the actual value of the railcars was less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of approximately $36

million. OG&E expects to enter into a new lease agreement for railcars effective April 1, 2006, which should negate any financial exposure under the current lease agreement. OG&E is also required to maintain the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities (including technology) at Enogex. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. 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.

Capital requirements and future contractual obligations estimated for the next five years and beyond are as follows:


					Less than									More	than
(In millions)		Total			1 year			1 - 3 ye	ars		3 - 5	years		5 years

OG&E capital expenditures including AFUDC (A)	$	647	.7	$	235	.7	$	412	.0		N/	A		N/	A
Enogex capital expenditures and acquisitions		77	.5		32	.2		45	.3		N/	A		N/	A
Other Operations capital expenditures		36	.1		12	.1		24	.0		N/	A		N/	A

Total capital expenditures		761	.3		280	.0		481	.3		N/	A		N/	A
Maturities of long-term debt		1,460	.4		146	.1		6	.6	$	4	.6	$	1,303	.1
Interest payments on long-term debt		1,042	.2		79	.2		144	.4		143	.4		675	.2
Pension funding obligations		123	.8		37	.4		61	.3		25	.1		N/	A

Total capital requirements		3,387	.7		542	.7		693	.6		173	.1		1,978	.3
Operating lease obligations
OG&E railcars		51	.7		5	.4		10	.7		10	.7		24	.9
Enogex noncancellable operating leases		8	.1		3	.7		4	.1		0	.2		0	.1

Total operating lease obligations		59	.8		9	.1		14	.8		10	.9		25	.0
Other purchase obligations and commitments
OG&E cogeneration capacity payments		465	.6		99	.5		194	.2		171	.9		N/	A
OG&E fuel minimum purchase commitments		907	.0		170	.8		319	.0		251	.7		165	.5
Other		75	.7		7	.4		14	.9		14	.9		38	.5

Total other purchase obligations and commitments		1,488	.3		277	.7		528	.1		438	.5		204	.0
Total capital requirements, operating lease obligations
and other purchase obligations and commitments		4,895	.8		829	.5		1,236	.5		622	.5		2,207	.3
Amounts recoverable through automatic fuel
adjustment clause (B)		(1,424	.3)		(275	.7)		(523	.9)		(434	.3)		(190	.4)

Total, net	$	3,471	.5	$	553	.8	$	712	.6	$	188	.2	$	2,016	.9

(A) Under current environmental laws and regulations, OG&E may be required to spend additional capital expenditures on its coal-fired plants. These expenditures would not begin until the year 2008. The amounts and timing of these expenditures is uncertain at the present time. (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 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. OG&E currently has pending before the OCC an application to recover the costs of gas transportation and storage services provided to it by Enogex pursuant to the contract between OG&E and Enogex. An adverse decision by the OCC could result in OG&E having to refund previously collected amounts. See Note 18 of Notes to Consolidated Financial Statements for a further discussion.

2004 Capital Requirements and Financing Activities

Total capital requirements, consisting of capital expenditures, maturities and retirements of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $840.0 million and contractual obligations, net of recoveries through automatic fuel adjustment clauses, were approximately $4.3 million resulting in total net capital requirements and contractual obligations of approximately $844.3 million in 2004. Approximately $7.8 million of the 2004 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $335.0 million and net contractual obligations of approximately $6.4 million totaling approximately $341.4 million in 2003, of which approximately $6.4 million was to comply with environmental regulations. During 2004, 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), issuance of long-term debt, proceeds from the sale of assets and the issuance of common stock pursuant to the Company’s DRIP/DSPP. 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 for 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.

Early Retirement of Long-Term Debt

In 1998, Enogex issued a note in the amount of approximately $5.7 million payable to an unaffiliated former partial interest owner of NOARK. The note had a maturity date of July 1, 2020 and an interest rate of 7.00 percent. Principal and interest payments of approximately $0.8 million were due annually beginning July 1, 2004. In July 2004, Enogex made the initial $0.8 million payment and also made a payment of approximately $7.8 million, which included accrued interest since inception of the note, to repay the outstanding note balance and satisfy its remaining obligations related to this note. Enogex recorded a pre-tax gain of approximately $0.1 million in the third quarter of 2004 related to this transaction.

Asset Sales

Also contributing to the liquidity of the Company have been numerous asset sales by the Company. Since January 1, 2002, significant completed sales transactions have generated net sales

proceeds of approximately $116.1 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.

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

Issuance of Long-Term Debt

In August 2004, OG&E issued $140.0 million of long-term debt. The proceeds were used to replace a portion of the short-term borrowings initially used to fund a portion of the McClain Plant acquisition in July 2004. This debt has a maturity date of August 1, 2034 and an interest rate of 6.50 percent.

In September 2004, the Company filed a Form S-3 Registration Statement registering the sale of up to $200.0 million of the Company’s unsecured debt securities. In November 2004, the Company issued $100.0 million of long-term debt, the proceeds of which were used to replace a portion of the short-term debt incurred to fund the redemption of the trust preferred securities on October 15, 2004. This new debt has a maturity date of November 15, 2014 and an interest rate of 5.00 percent.

Long-term Debt Maturities

During 2004 and 2003, approximately $51.0 million and $19.0 million, respectively, of Enogex’s long-term debt matured and approximately $10.3 million and $12.0 million, respectively, was redeemed during 2004 and 2003 which is itemized in the following table.

(In millions)		2004			2003

Series Due 2003 -- 6.60% - 8.28%	$	-	--	$	19	.0
Series Due 2004 -- 6.71% - 8.34%		51	.0		-	--
Series Due 2018 -- 7.15%		2	.0		2	.0
Series Due 2020 -- 7.00%		8	.3		-	--
Series Due 2023 -- 7.75%		-	--		10	.0

Total	$	61	.3	$	31	.0

Maturities of the Company’s long-term debt during the next five years consist of $146.1 million in 2005; $1.8 million in 2006; $4.8 million in 2007; $2.8 million in 2008 and $1.8 million in 2009. For OG&E, $110.0 million of long-term debt matures in 2005; however, in the Consolidated Statement of Capitalization at December 31, 2004, no amount is shown as Long-Term Debt Due Within One Year. The Company plans to refinance this amount and the Company believes they have the ability to do so as the Company and OG&E entered into new five-year revolving credit agreements in October 2004 in an amount up to $550 million which could be utilized to temporarily finance these notes when they mature in October 2005.

Interest Rate Swap Agreements

Fair Value Hedges

Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert a total of $200.0 million ($100.0 million for each interest rate swap agreement) of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR in arrears. The objective of these 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. These interest rate swaps qualified as fair value hedges under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

At December 31, 2004 and 2003, the fair values pursuant to the interest rate swaps were approximately $7.9 million and $7.6 million, respectively, and the hedges were classified as Deferred Charges and Other Assets – Price Risk Management in the Consolidated Balance Sheets. A corresponding net increase of approximately $7.9 million and $7.6 million was reflected in Long-Term Debt at December 31, 2004 and 2003, respectively, as these fair value hedges were effective at December 31, 2004 and 2003.

Cash Flow Hedges

The Company entered into four separate interest rate swap agreements, effective April 16, 2004, April 21, 2004, May 17, 2004 and July 16, 2004, respectively, to hedge approximately $20.0 million, $30.0 million, $20.0 million and $10.0 million, respectively, of future interest payments of long-term debt that was issued in November 2004. These interest rate swap agreements originally matured on October 15, 2004 but the maturity date was extended to November 8, 2004. The Company terminated these cash flow hedges on November 9, 2004, at which time approximately $4.0 million was recorded in other comprehensive income. This amount will be amortized to interest expense over the life of the related long-term debt.

Trust Originated Preferred Securities

On October 21, 1999, OGE Energy Capital Trust I, a wholly-owned financing trust of the Company, issued $200.0 million principal amount of 8.375 percent trust preferred securities with a maturity date of October 15, 2039. On October 15, 2004, the Company caused all of the outstanding trust preferred securities to be redeemed at $25 per share (100 percent of liquidation value). The redemption was initially funded with cash on hand and approximately $170.0 million in commercial paper. The Company refinanced a portion of this short-term debt with $100.0 million of long-term debt issued in November 2004. In October 2004, the Company wrote off approximately $5.9 million related to unamortized debt issuance costs for the trust preferred securities.

Future Capital Requirements

Capital Expenditures

The Company’s current 2005 to 2007 construction program includes continued investment in system and transmission upgrades that is part of the Company’s Customer Savings and Reliability Plan. OG&E has approximately 430 MWs of QF contracts that will expire at the end of 2007, unless extended by OG&E. In addition, effective September 1, 2004, OG&E entered into a new 15-year power sales agreement for 120 MWs with PowerSmith. OG&E will continue reviewing all of the supply alternatives to these expiring 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. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units. See Note 18 of Notes to Consolidated Financial Statements for a description of the new PowerSmith QF contract.

To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $7.0 million of the Company’s capital expenditures budgeted for 2005 are to comply with environmental laws and regulations.

Pension and Postretirement Benefit Plans

During 2004, actual asset returns for the Company’s defined benefit pension plan were positively affected by growth in the equity markets; however, the growth in 2004 was not as strong as the growth in the equity markets in 2003. Approximately 62 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 2004, asset returns on the pension plan were approximately 12.51 percent as compared to approximately 22.76 percent in 2003. During the same time, 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 $50.0 million in 2003 to approximately $69.0 million in 2004. This increase was necessitated by the lower investment returns on assets and lower discount rates used to value the accumulated pension benefit obligations. During 2005, the Company plans to contribute approximately $37.4 million to the pension plan. 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.

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.

During 2004 and 2003, the Company made contributions to the pension plan and the restoration of retirement income plan that exceeded amounts previously recognized as net periodic pension expense and recorded a net prepaid benefit obligation at December 31, 2004 and 2003 of approximately $92.0 million and $55.7 million, respectively. At December 31, 2004 and 2003, the Company’s projected pension benefit obligation exceeded the fair value of the pension plan assets and the restoration of retirement income plan assets by approximately $123.3 million and $131.8 million, respectively. 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, “Employers’ Accounting for Pensions,” required the recognition of an additional minimum liability in the amount of approximately $156.6 million and $137.6 million, respectively, at December 31, 2004 and 2003. 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

2004 or 2003 and did not require a usage of cash and is therefore excluded from the Consolidated Statements 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.

Security Ratings

	Moody’s	Standard & Poor’s	Fitch’s
OG&E Senior Notes	A2	BBB+	AA-
Enogex Notes	Baa3	BBB+	BBB
OGE Energy Corp. Senior Notes	Baa1	BBB	A
OGE Energy Corp. Commercial Paper	P-2	A-2	F1

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, 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, proceeds from the sales of common stock pursuant to the Company’s DRIP/DSPP and long and short-term debt will be adequate over the next three years to meet anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. As discussed below, 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

The following table shows the Company’s lines of credit in place and available cash at January 31, 2005. At January 31, 2005, the Company’s short-term borrowings consisted of commercial paper.

Lines of Credit and Available Cash (In millions)
Entity	Amount Available	Amount Outstanding	Maturity
OGE Energy Corp.	$ 15.0	$ ---	April 6, 2004
OG&E	100.0	---	October 20, 2009 (B)
OGE Energy Corp. (A)	450.0	---	October 20, 2009 (B)
	565.0	---
Cash	14.9	N/A	N/A
Total	$ 579.9	$ ---
(A) These lines of credit are used to back up a maximum of $300.0 million of the Company’s commercial paper borrowings, which were approximately $187.6 million at January 31, 2005. (B) Each of the new credit facilities has a five-year term with two options to extend the term for one year.

On October 20, 2004, the Company and OG&E entered into revolving credit agreements totaling $550 million. These agreements include two separate credit facilities, one for the Company in an amount up to $450 million and one for OG&E in an amount up to $100 million. Each of the new credit facilities has a five-year term with two options to extend the term for one year. Planned uses of the revolving credit include working capital needs, back-up for the Company’s commercial paper program, the issuance of letters of credit and for general corporate purposes.

The Company’s and OG&E’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade. Their respective back-up lines of credit contain rating grids that require annual fees and borrowing rates to increase if they suffer an adverse ratings impact. The impact of any future downgrades would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes.

Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time. In November 2004, OG&E received approval from the FERC to incur up to $400 million in short-term borrowings for an additional two-year period beginning January 1, 2005 through December 31, 2006.

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, accrued removal obligations, regulatory assets and liabilities, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchase and sale contracts and natural gas storage inventory and fair value and cash flow hedging policies. 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 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 increases in discount rates will reduce funding requirements to the plan. The following table indicates the sensitivity of the pension plans funded status to these variables.

	Change	Impact on Funded Status

Actual plan asset returns	+/- 5 percent	+/- $18.1 million
Discount rate	+/- 0.25 percent	+/- $18.6 million
Contributions	+ $10.0 million	+ $10.0 million
Expected long-term return on plan assets	+/- 1 percent	None

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 determined or included in the 2005 earnings guidance.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. The scope of SFAS No. 143 includes the Company’s accrued plant removal costs for generation, transmission, distribution, processing and pipeline assets. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to remove certain assets associated with their retirements. As the Company currently has no plans to retire any of these assets (except as discussed

below) and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. During the third quarter of 2004, OG&E determined the definite life of a legal obligation within the scope of SFAS No. 143 to retire certain assets related to the expiration of a power supply contract in June 2006. OG&E recorded an asset retirement obligation of approximately $1.1 million at September 30, 2004 and began amortizing this amount for 21 months beginning October 1, 2004.

The Company expects that the FASB will issue an interpretation related to SFAS No. 143 during the first quarter of 2005 in which an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation would be recognized when incurred. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability rather than the recognition of the liability. However, in some cases, there is insufficient information to estimate the fair value of an asset retirement obligation. In these cases, the liability would be initially recognized in the period in which sufficient information is available for an entity to make a reasonable estimate of the liability’s fair value. The Company expects that this interpretation will be effective no later than the end of fiscal years ending after December 15, 2005. Additionally, the interpretation is expected to permit, but not require, restatement of interim financial information during any period of adoption. The FASB also has indicated that it will require both recognition of a cumulative change in accounting principle and disclosure of the liability on a pro forma basis for transition purposes. The Company will evaluate the financial impact when a final interpretation is issued.

OG&E and Enogex engage in cash flow and fair value hedge transactions to manage commodity risk and modify the rate composition of the debt portfolio. 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 hedging requirements and are executed based upon management established price targets. During 2003, OERI also utilized fair value hedges under SFAS No. 133 to manage commodity price exposure for natural gas storage inventory. However, during 2004, OERI decided not to utilize hedge accounting under SFAS No. 133 for natural gas storage inventory. 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 have entered into interest rate swap agreements on the debt portfolio to modify the interest rate exposure on fixed rate debt issues. These interest rate swaps qualify as fair value hedges under SFAS No. 133. The objective of these 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.

Electric Utility Segment

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. Excluding recoverable take or pay gas charges, the McClain Plant operating and maintenance expenses, depreciation, ad valorem taxes and interest on debt, regulatory assets are being amortized and reflected in rates charged to customers over periods of up to 20 years.

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.

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, 2004, 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 $0.5 million. At December 31, 2004 and 2003, Accrued Unbilled Revenues were approximately $45.5 million and $38.0 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Customer balances are generally written off if not collected within six months after the original due 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, 2004, 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 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 $2.7 million and $2.6 million at December 31, 2004 and 2003, respectively.

Natural Gas Pipeline Segment

Operating revenues for transportation, storage, gathering and processing services for Enogex are estimated each month based on the prior month’s activity, 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 on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.

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.

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 Company utilizes a model to estimate the fair value of its energy contracts including derivatives that do not have an independent market price. At December 31, 2004, unrealized mark-to-market gains were approximately $20.7 million, which included approximately $0.4 million of unrealized mark-to-market gains that were calculated utilizing models. At December 31, 2004, a price movement of one percent for prices verified by independent parties would result in changes in unrealized mark-to-market gains of approximately $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 and liabilities on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income. See Note 2 of Notes to Consolidated Financial Statements for a further discussion of accounting for energy contracts.

Effective January 1, 2003, natural gas storage inventory used in OERI’s business activities are accounted for at the lower of cost or market in accordance with the guidance in EITF 02-3 which resulted in the rescission of EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as amended. Prior to January 1, 2003, this inventory was accounted for on a fair value accounting basis utilizing a gas index that in management’s opinion approximated the current market value of natural gas in that region as of the Balance Sheet date. On April 1, 2003, natural gas storage inventory used in OERI’s business activities began to be accounted for under SFAS No. 133. In order to minimize risk, OERI enters into contracts or hedging instruments to hedge the fair value of this inventory. For any contracts that qualify for hedge accounting under SFAS No. 133, the hedged portion of the inventory is recorded at fair value with an offsetting gain or loss recorded currently in earnings. During 2003, OERI utilized hedge accounting under SFAS No. 133 for natural gas storage inventory; however, during 2004, OERI decided not to utilize hedge accounting under SFAS No. 133 for natural gas storage inventory. Ineffectiveness associated with OERI’s fair value hedge strategy was not material. The fair value of the hedging instrument is also recorded on the books of OERI as a Price Risk Management asset or liability with an offsetting gain or loss recorded in current earnings. As part of its recurring business activity, OERI injects and withdraws natural gas under the terms of storage capacity contracts; the amount of natural gas inventory was approximately $29.0 million and $82.4 million at December 31, 2004 and 2003, respectively. See Note 2 of Notes to Consolidated Financial Statements for a further discussion. 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.

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 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 $1.8 million and $1.6 million at December 31, 2004 and 2003, respectively.

Accounting Pronouncements

See Note 2 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 it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail in Note 18 of Notes to Consolidated Financial Statements. OG&E currently has one important matter pending before the OCC. See Note 18 of Notes of Consolidated Financial Statements for a further discussion.

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 regulatory agencies. Management consults with 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. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of currently 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. This assessment of currently pending or threatened lawsuits is subject to change. See Note 17 of Notes to Consolidated Financial Statements for a discussion of the Company’s commitments and contingencies.

Quantitative and Qualitative Disclosures About Market Risk.

Risk Management

The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its businesses. A corporate risk management department, under the direction of a corporate risk oversight committee, has been established to review these risks on a regular basis. The Company is exposed to market risk in its normal course of business, including changes in certain commodity prices and interest rates. The Company also engages in price risk management activities for both trading and non-trading purposes.

To manage the volatility relating to these exposures, the Company enters into various derivative and other forward transactions pursuant to the Company’s policies on hedging practices. These positions are monitored using techniques such as mark-to-market valuation, value-at-risk and sensitivity analysis.

Interest Rate Risk

The Company’s exposure to changes in interest rates relates primarily to long-term debt obligations 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 rate 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.

Fair Value Hedges

At December 31, 2004 and 2003, the Company had three outstanding interest rate swap agreements that qualified as fair value hedges: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month LIBOR and (ii) Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert a total of $200.0 million ($100.0 million for each interest rate swap agreement) of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR in arrears. The objective of these 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. These interest rate swaps qualified as fair value hedges under SFAS No. 133 and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133.

Cash Flow Hedges

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. The valuation of the Company’s interest rate swaps was determined primarily based on quoted market prices. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.


																							12/31/04
(Dollars in millions)		2005			2006			2007			2008			2009			Thereaft	er		Total			Fair Value

Fixed rate debt
Principal amount	$	146	.1	$	1	.8	$	4	.8	$	2	.8	$	1	.8	$	845	.5	$	1,002	.8	$	1,097	.6
Weighted-average
interest rate		7.07	%		7.15	%		7.83	%		7.12	%		7.15	%		6.77	%		6.82	%		-	--
Variable rate debt
Principal amount (A)		-	--		-	--		-	--		-	--		-	--	$	457	.6	$	457	.6	$	458	.2
Weighted-average
interest rate		-	--		-	--		-	--		-	--		-	--		3.45	%		3.45	%		-	--

(A) Amount includes an increase to the fair value of long-term debt of approximately $7.9 million due to the Company’s interest rate swaps.

Commodity Price Risk

The market risks inherent in the Company’s market risk sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the commodity prices to which the Company is exposed. These market risks can be classified as trading, which includes transactions that are entered into voluntarily to capture subsequent changes in commodity prices, or non-trading, which includes the exposure some of the Company’s assets have to commodity prices.

The trading activities are conducted throughout the year subject to daily and monthly trading stop loss limits of $2.5 million. The daily loss exposure from trading activities is measured primarily using value at risk, subject to a $1.5 million limit, as well as other quantitative risk measurement techniques. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company’s operating income.

The prices of natural gas, natural gas liquids and natural gas liquids processing spreads are subject to fluctuations resulting from changes in supply and demand. The changes in these prices have a direct effect on the operating income received by the Company as compensation for operating some of its assets. To partially reduce non-trading commodity price risk incurred in the Company’s normal

course of business caused by these market fluctuations, the Company hedges, through the utilization of derivatives and other forward transactions, the effects these market fluctuations have on the operating income received by the Company as compensation for operating these assets. Because the commodities covered by these hedges are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

Sensitivity analyses have been prepared to estimate the Company’s exposure to the market risk of the Company’s natural gas and natural gas liquids commodity positions. These analyses are done for both trading and non-trading activities. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. The value of trading positions is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Because quoted market prices are not available for all of the Company’s non-trading positions, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forecast prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The results of these analyses, which may differ from actual results, are as follows for 2004.

(In millions)		Trading		Non-	Trading

Commodity market risk, net	$	0.3	$	7	.8

Financial Statements and Supplementary Data.

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS


December 31 (In millions)		2004			2003

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	26	.4	$	245	.6
Accounts receivable, net		487	.9		350	.2
Accrued unbilled revenues		45	.5		38	.0
Fuel inventories		89	.0		149	.6
Materials and supplies, at average cost		53	.2		45	.1
Price risk management		118	.6		61	.3
Gas imbalances		100	.1		70	.0
Accumulated deferred tax assets		13	.7		9	.4
Fuel clause under recoveries		54	.3		4	.0
Recoverable take or pay gas charges		17	.0		-	--
Other		13	.5		21	.5

Total current assets		1,019	.2		994	.7

OTHER PROPERTY AND INVESTMENTS, at cost		31	.4		34	.7

PROPERTY, PLANT AND EQUIPMENT
In service		5,957	.6		5,610	.0
Construction work in progress		110	.5		56	.7
Other		5	.8		15	.0

Total property, plant and equipment		6,073	.9		5,681	.7
Less accumulated depreciation		2,492	.9		2,358	.5

Net property, plant and equipment		3,581	.0		3,323	.2


DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		-	--		32	.5
Income taxes recoverable from customers, net		30	.9		31	.6
Intangible asset - unamortized prior service cost		38	.0		40	.2
Prepaid benefit obligation		92	.7		55	.7
Price risk management		19	.6		13	.5
Other		57	.5		58	.6

Total deferred charges and other assets		238	.7		232	.1

TOTAL ASSETS	$	4,870	.3	$	4,584	.7

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS (Continued)

December 31 (In millions)		2004			2003

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	125	.0	$	202	.5
Accounts payable		476	.2		280	.2
Dividends payable		29	.9		29	.1
Customers’ deposits		48	.3		41	.6
Accrued taxes		14	.1		18	.7
Accrued interest		33	.2		30	.7
Accrued interest - unconsolidated affiliate		-	--		3	.5
Tax collections payable		7	.2		7	.9
Accrued vacation		17	.9		17	.2
Long-term debt due within one year		35	.1		52	.1
Non-recourse debt of joint venture		1	.2		1	.2
Price risk management		102	.9		46	.9
Gas imbalances		22	.8		22	.5
Fuel clause over recoveries		-	--		32	.4
Provision for payments of take or pay gas		21	.0		-	--
Other		40	.6		41	.2

Total current liabilities		975	.4		827	.7

LONG-TERM DEBT
Long-term debt		1,385	.1		1,189	.7
Non-recourse debt of joint venture		39	.0		40	.2
Long-term debt - unconsolidated affiliate		-	--		206	.2

Total long-term debt		1,424	.1		1,436	.1


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		197	.0		167	.4
Accumulated deferred income taxes		802	.0		747	.3
Accumulated deferred investment tax credits		36	.8		42	.0
Accrued removal obligations, net		122	.2		116	.3
Price risk management		6	.6		4	.5
Provision for payments of take or pay gas		-	--		32	.5
Asset retirement obligation		1	.1		-	--
Other		19	.5		9	.3

Total deferred credits and other liabilities		1,185	.2		1,119	.3


STOCKHOLDERS’ EQUITY
Common stockholders’ equity		700	.8		636	.1
Retained earnings		659	.8		623	.9
Accumulated other comprehensive loss, net of tax		(75	.0)		(58	.4)

Total stockholders’ equity		1,285	.6		1,201	.6


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,870	.3	$	4,584	.7

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31 (In millions)		2004			2003

STOCKHOLDERS’ EQUITY
Common stock, par value $0.01 per share; authorized 125.0 shares;
and outstanding 90.0 and 87.4 shares, respectively	$	0	.9	$	0	.9
Premium on capital stock		699	.9		635	.2
Retained earnings		659	.8		623	.9
Accumulated other comprehensive loss, net of tax		(75	.0)		(58	.4)

Total stockholders’ equity		1,285	.6		1,201	.6

LONG-TERM DEBT
SERIES	DATE DUE
Senior Notes-OGE Energy Corp.
5.00 %	Senior Notes, Series Due November 15, 2014	100	.0	-	--
Unamortized discount		(0	.9)	-	--
Senior Notes-OG&E
7.125 %	Senior Notes, Series Due October 15, 2005	110	.0	110	.0
6.50 %	Senior Notes, Series Due July 15, 2017	125	.0	125	.0
Variable %	Senior Notes, Series Due October 15, 2025	114	.0	114	.0
6.65 %	Senior Notes, Series Due July 15, 2027	125	.0	125	.0
6.50 %	Senior Notes, Series Due April 15, 2028	100	.0	100	.0
6.50 %	Senior Notes, Series Due August 1, 2034	140	.0	-	--
Other bonds-OG&E
Variable %	Garfield Industrial Authority, January 1, 2025	47	.0	47	.0
Variable %	Muskogee Industrial Authority, January 1, 2025	32	.4	32	.4
Variable %	Muskogee Industrial Authority, June 1, 2027	56	.0	56	.0
Unamortized discount		(2	.2)	(2	.2)
Enogex Notes
6.71% - 8.34%	Medium-Term Notes, Series Due 2004	-	--	51	.0
6.81% - 6.99%	Medium-Term Notes, Series Due 2005	34	.3	34	.2
8.28%	Medium-Term Notes, Series Due 2007	3	.0	3	.0
7.07%	Medium-Term Notes, Series Due 2008	1	.0	1	.0
8.125%	Medium-Term Notes, Series Due 2010	200	.0	200	.0
Variable %	Medium-Term Notes, Series Due 2010	208	.8	209	.5
7.15%	Medium-Term Notes, Series Due 2018	67	.0	69	.0
7.00%	Medium-Term Notes, Series Due 2020	-	--	8	.3

Unconsolidated affiliate (Note 12)		-	--	206	.2

Total long-term debt		1,460	.4		1,489	.4
Less long-term debt due within one year		35	.1		52	.1
Non-recourse of joint venture		1	.2		1	.2

Total long-term debt (excluding long-term debt due within one year)		1,424	.1		1,436	.1

Total Capitalization	$	2,709	.7	$	2,637	.7

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME

Year ended December 31 (In millions, except per share data)		2004			2003			2002

OPERATING REVENUES
Electric Utility operating revenues	$	1,578	.1	$	1,517	.1	$	1,388	.0
Natural Gas Pipeline operating revenues		3,348	.5		2,261	.9		1,635	.9

Total operating revenues		4,926	.6		3,779	.0		3,023	.9
COST OF GOODS SOLD
Electric Utility cost of goods sold		865	.0		792	.7		662	.2
Natural Gas Pipeline cost of goods sold		3,097	.7		2,053	.3		1,458	.1

Total cost of goods sold		3,962	.7		2,846	.0		2,120	.3

Gross margin on revenues		963	.9		933	.0		903	.6
Other operation and maintenance		392	.2		371	.7		370	.0
Depreciation		178	.6		176	.9		182	.5
Impairment of assets		7	.8		10	.2		50	.1
Taxes other than income		67	.8		67	.3		65	.3

OPERATING INCOME		317	.5		306	.9		235	.7

OTHER INCOME (EXPENSE)
Other income		12	.1		8	.1		3	.7
Other expense		(5	.5)		(9	.0)		(4	.7)

Net other income (expense)		6	.6		(0	.9)		(1	.0)

INTEREST INCOME (EXPENSE)
Interest income		5	.2		1	.3		1	.7
Interest on long-term debt		(74	.4)		(75	.2)		(86	.2)
Interest on trust preferred securities		-	--		-	--		(17	.3)
Interest expense - unconsolidated affiliate		(13	.7)		(17	.3)		-	--
Allowance for borrowed funds used during construction		1	.7		0	.5		0	.9
Interest on short-term debt and other interest charges		(9	.7)		(6	.0)		(8	.2)

Net interest expense		(90	.9)		(96	.7)		(109	.1)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES		233	.2		209	.3		125	.6
INCOME TAX EXPENSE		80	.2		73	.7		44	.6

INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE		153	.0		135	.6		81	.0
DISCONTINUED OPERATIONS (NOTE 4)
Income from discontinued operations		0	.8		1	.8		8	.4
Income tax expense (benefit)		0	.3		2	.2		(1	.4)

Income (loss) from discontinued operations		0	.5		(0	.4)		9	.8

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE		153	.5		135	.2		90	.8
CUMULATIVE EFFECT ON PRIOR YEARS OF CHANGE
IN ACCOUNTING PRINCIPLE, net of tax of $3.4		-	--		(5	.4)		-	--

NET INCOME	$	153	.5	$	129	.8	$	90	.8

BASIC AVERAGE COMMON SHARES OUTSTANDING		88	.0		81	.8		78	.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING		88	.5		82	.1		78	.2
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income from continuing operations	$	1.7	3	$	1.6	6	$	1.0	4
Income from discontinued operations, net of tax		0.0	1		--	-		0.1	2
Loss from cumulative effect of accounting change, net of tax		--	-		(0.0	7)		--	-

NET INCOME	$	1.7	4	$	1.5	9	$	1.1	6

DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income from continuing operations	$	1.7	2	$	1.6	5	$	1.0	4
Income from discontinued operations, net of tax		0.0	1		--	-		0.1	2
Loss from cumulative effect of accounting change, net of tax		--	-		(0.0	7)		--	-

NET INCOME	$	1.7	3	$	1.5	8	$	1.1	6

DIVIDENDS DECLARED PER SHARE	$	1.3	3	$	1.3	3	$	1.3	3

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

Year ended December 31 (In millions)		2004			2003			2002

BALANCE AT BEGINNING OF PERIOD	$	623	.9	$	604	.7	$	617	.9
ADD: Net income		153	.5		129	.8		90	.8

Total		777	.4		734	.5		708	.7

DEDUCT: Dividends declared on common stock		117	.6		110	.6		104	.0

BALANCE AT END OF PERIOD	$	659	.8	$	623	.9	$	604	.7

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31 (In millions)		2004			2003			2002

Net income	$	153	.5	$	129	.8	$	90	.8
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment [($21.2), $23.8 and ($85.5) pre-tax,
respectively]		(13	.0)		14	.6		(52	.4)
Reclassification adjustments - contract settlements [$0.2 pre-tax]		-	--		-	--		0	.1
Deferred hedging gains (losses) [($1.1) and $1.5 pre-tax, respectively]		(0	.7)		0	.9		-	--
(Reversal of unrealized gain) unrealized gains on available-for-sale securities [($0.6) and $0.6 pre-tax, respectively]		(0	.4)		0	.4		-	--
Settlement of cash flow hedge [($4.0) pre-tax]		(2	.5)		-	--		-	--

Total other comprehensive income (loss), net of tax		(16	.6)		15	.9		(52	.3)

Total comprehensive income	$	136	.9	$	145	.7	$	38	.5

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31 (In millions)		2004			2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	153	.5	$	129	.8	$	90	.8
Adjustments to reconcile net income to net cash provided from operating
activities
(Income) loss from discontinued operations		(0	.5)		0	.4		(9	.8)
Cumulative effect of change in accounting principle		-	--		5	.4		-	--
Depreciation		178	.6		176	.9		182	.5
Impairment of assets		7	.8		10	.2		50	.1
Deferred income taxes and investment tax credits, net		53	.1		116	.3		33	.1
Allowance for equity funds used during construction		(0	.9)		-	--		-	--
Gain on sale of assets		(6	.5)		(6	.1)		(1	.0)
Ineffectiveness of interest rate swap		-	--		-	--		0	.2
Price risk management assets		(63	.1)		(45	.8)		4	.8
Price risk management liabilities		52	.5		36	.7		16	.4
Other assets		(27	.2)		(6	.7)		(36	.8)
Other liabilities		11	.0		0	.8		(8	.6)
Change in certain current assets and liabilities
Accounts receivable, net		(137	.7)		(45	.6)		(83	.5)
Accrued unbilled revenues		(7	.5)		(9	.8)		7	.4
Fuel, materials and supplies inventories		52	.5		(54	.8)		(26	.5)
Gas imbalances asset		(30	.1)		(22	.3)		(32	.4)
Fuel clause under recoveries		(50	.3)		10	.7		(14	.7)
Other current assets		3	.5		(2	.3)		(1	.1)
Accounts payable		196	.0		18	.5		108	.5
Customers’ deposits		6	.7		1	.0		12	.1
Accrued taxes		(4	.6)		(1	.6)		(4	.8)
Accrued interest		(1	.0)		(1	.4)		(4	.2)
Fuel clause over recoveries		(32	.4)		32	.4		(23	.4)
Gas imbalances liability		0	.3		(0	.3)		16	.3
Other current liabilities		5	.8		19	.4		7	.9

Net Cash Provided from Operating Activities		359	.5		361	.8		283	.3

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)		(431	.8)		(181	.3)		(234	.5)
Proceeds from sale of assets		9	.3		16	.2		1	.7
Other investing activities		0	.7		1	.6		(0	.5)

Net Cash Used in Investing Activities		(421	.8)		(163	.5)		(233	.3)

CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(267	.4)		(31	.0)		(140	.0)
(Decrease) increase in short-term debt, net		(77	.5)		(72	.5)		126	.2
Proceeds from long-term debt		237	.0		-	--		-	--
Premium on issuance of common stock		62	.5		171	.3		3	.1
Distribution from (to) minority interest		2	.6		(2	.5)		-	--
Dividends paid on common stock		(114	.6)		(98	.6)		(99	.5)

Net Cash Used in Financing Activities		(157	.4)		(33	.3)		(110	.2)

DISCONTINUED OPERATIONS
Net cash provided from (used in) operating activities		0	.5		(1	.9)		17	.2
Net cash provided from investing activities		-	--		38	.1		51	.3
Net cash used in financing activities		-	--		-	--		(1	.4)

Net Cash Provided from Discontinued Operations		0	.5		36	.2		67	.1

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(219	.2)		201	.2		6	.9
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		245	.6		44	.4		37	.5

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	26	.4	$	245	.6	$	44	.4

The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization

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. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates Ozark Gas Transmission, L.L.C. (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, was sold in 2002 and in the first quarter of 2003 and are reported in the Consolidated Financial Statements as discontinued operations. During the third quarter of 2004, Enogex entered into a joint venture arrangement with a third party and contributed certain of its natural gas compression assets to use in the joint venture, whose primary business focus will be the rental of compression assets. Enogex created a wholly-owned limited liability company, Enogex Compression Company, LLC (“Enogex Compression”), to act as the participating entity in the joint venture. Enogex Compression holds a majority ownership in the joint venture and the third party acts as the manager and conducts the daily operations of the joint venture. Enogex Compression has been consolidated in the Company’s financial statements with a minority interest recorded.

The Company allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income

and assets. The Company believes this method provides a reasonable basis for allocating common expenses

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“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. Excluding recoverable take or pay gas charges, the McClain Plant operating and maintenance expenses, depreciation, ad valorem taxes and interest on debt in the table below, regulatory assets are being amortized and reflected in rates charged to customers over periods of up to 20 years.

The following table is a summary of OG&E’s regulatory assets and liabilities at December 31:

(In millions)		2004			2003

Regulatory Assets
Fuel clause under recoveries	$	54	.3	$	4	.0
Recoverable take or pay gas charges		17	.0		32	.5
Income taxes recoverable from customers, net		30	.9		31	.6
Unamortized loss on reacquired debt		21	.0		22	.1
McClain Plant expenses		11	.0		-	--
January 2002 ice storm		1	.8		3	.6
Arkansas transition costs		0	.7		-	--
Miscellaneous		0	.6		0	.4

Total Regulatory Assets	$	137	.3	$	94	.2


Regulatory Liabilities
Accrued removal obligations, net	$	122	.2	$	116	.3
Estimated refund on gas transportation and storage case		6	.9		-	--
Estimated refund on FERC fuel		1	.0		1	.0
Fuel clause over recoveries		-	--		32	.4

Total Regulatory Liabilities	$	130	.1	$	149	.7

Fuel clause under recoveries are generated from under recoveries from OG&E’s customers when OG&E’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E’s customers when the amount billed to its customers exceeds OG&E’s cost of fuel. OG&E’s fuel recovery clauses are designed to smooth the

impact of fuel price volatility on customers’ bills. As a result, OG&E 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 allow OG&E to amortize under or over recovery. OG&E expects to recover the fuel clause under recoveries during 2005.

Recoverable take or pay gas charges represent OG&E’s estimate of the maximum amount that it could be obligated to pay under certain take-or-pay contracts. OG&E believes that it is entitled to recover any such amounts from its customers through its regulatorily approved automatic fuel adjustment clauses or other regulatory mechanisms.

Income taxes recoverable from customers represent income tax benefits previously used to reduce OG&E’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed OG&E to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The income tax related regulatory assets and liabilities are netted on the Company’s Consolidated Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E’s long-term debt. These amounts are being recovered over the term of the long-term debt which replaced the previous long-term debt.

As a result of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the 2002 agreed-upon settlement of OG&E’s rate case (the “Settlement Agreement”) with the OCC, OG&E has the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. All prudently incurred costs accrued through the regulatory asset within the 12-month period would be included in OG&E’s prospective cost of service and would be recovered over a period to be determined by the OCC.

On November 22, 2002, the OCC signed a rate order containing the provisions of a Settlement Agreement of OG&E’s rate case. The Settlement Agreement provides for, among other things, recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for sales to other utilities and power marketers (“off-system sales”). Previously, OG&E had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs. During the year ended December 31, 2004, OG&E recovered approximately $1.8 million in annual net profits from off-system sales, gave approximately $3.6 million in annual net profits from off-system sales to OG&E’s Oklahoma customers and the net profits from off-system sales that exceeded the $5.4 million were shared with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E.

In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, which had initially targeted customer choice of electricity providers by January 1, 2002, was repealed in March 2003 before it was implemented. As part of the repeal legislation, electric public utilities were permitted to recover transition costs. OG&E incurred approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to implement retail open access. On January 20, 2004, the APSC issued an order which authorized OG&E to recover approximately $1.9 million in transition costs over an 18-month period beginning February 2004.

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” OG&E was required to reclassify its accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability.

On November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement of OG&E’s rate case. As part of the Settlement Agreement, OG&E agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. The prescribed bidding process detailed in the Settlement Agreement provided that each generation facility seek bids separately for the services required. OG&E believes that in order for it to achieve maximum coal generation, deliver the lowest cost energy to its customers and ensure reliable electric service, it must have integrated, firm no-notice load following service for both gas transportation and gas storage. On April 29, 2003, as required by the Settlement Agreement, OG&E filed an application with the OCC in which OG&E advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. On October 22, 2004, the administrative law judge overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with OG&E refunding to its customers any demand fees collected in excess of this amount. If this recommendation is ultimately accepted, OG&E believes its refund obligation would be approximately $6.9 million at December 31, 2004, which the Company does not believe is material in light of previously established reserves. See Note 18 for a further discussion.

Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is reduced or written off, as appropriate. If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

Use of Estimates

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, accrued removal obligations, regulatory assets and liabilities, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchase and sale contracts and natural gas storage inventory and fair value and cash flow hedging policies.

Cash and Cash Equivalents

For purposes of the Consolidated Financial Statements, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

The Company’s cash management program utilizes controlled disbursement banking arrangements. Outstanding checks in excess of cash balances were approximately $33.9 million and $38.7 million at December 31, 2004 and 2003, respectively, and are classified as Accounts Payable in the Consolidated Balance Sheets. Sufficient funds were available to fund these outstanding checks when they were presented for payment.

Allowance for Uncollectible Accounts Receivable

For OG&E, customer balances are generally written off if not collected within six months after the original due date. The allowance for uncollectible accounts receivable for OG&E 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. The allowance for uncollectible accounts receivable for Enogex 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 was approximately $4.5 million and $4.2 million at December 31, 2004 and 2003, respectively.

For OG&E, new business customers are required to provide a security deposit in the form of a case, bond, or irrevocable letter of credit which is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit which is refunded after 12 months of good payment history per the regulatory rules. The payment behavior of all existing customers is monitored and if the payment behavior indicates sufficient risk per the regulatory rules, customers will be required to provide a security deposit.

For Enogex, credit risk is the risk of financial loss to Enogex if counterparties fail to perform their contractual obligations. Enogex maintains credit policies with regard to its counterparties that management believes minimize overall credit risk. These policies include the evaluation of a potential counterparty’s financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements which provide for the netting of cash flows associated with a single counterparty. Enogex also monitors the financial condition of existing counterparties on an ongoing basis.

Fuel Inventories

OG&E

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $13.7 million and $24.9 million for 2004 and 2003, respectively, based on the average cost of fuel purchased. The amount of fuel inventory was approximately $42.2 million and $60.0 million at December 31, 2004 and 2003, respectively.

Effective December 31, 2003, approximately $13.7 million of natural gas storage inventory that was previously classified as Fuel Inventories was reclassified to Property, Plant and Equipment on the Consolidated Balance Sheet due to the gas transportation and storage contract between OG&E and Enogex requiring a minimum volume of natural gas be kept in the Enogex system.

Enogex

Effective January 1, 2003, natural gas storage inventory used in OGE Energy Resources, Inc.’s (“OERI”) business activities are accounted for at the lower of cost or market in accordance with the guidance in Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which resulted in the rescission of EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as amended. Prior to January 1, 2003, OERI’s inventory was accounted for on a fair value accounting basis utilizing a gas index that in management’s opinion approximated the current market value of natural gas in that region as of the Balance Sheet date. On April 1, 2003, natural gas storage inventory used in OERI’s business activities began to be accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. In order to minimize risk, OERI enters into contracts or hedging instruments to hedge the fair value of this inventory. For any contracts that qualify for hedge accounting under SFAS No. 133, the hedged portion of the inventory is recorded at fair value with an offsetting gain or loss recorded currently in earnings. Ineffectiveness associated with OERI’s fair value hedge strategy was not material in 2003 or 2004. The fair value of the hedging instrument is also recorded on the books of OERI as a Price Risk Management asset or liability with an offsetting gain or loss recorded in current earnings. During 2003, OERI utilized hedge accounting under SFAS No. 133 for natural gas storage inventory; however, during 2004, OERI decided not to utilize hedge accounting under SFAS No. 133 for natural gas storage inventory. As part of its recurring business activity, OERI injects and withdraws natural gas under the terms of storage capacity contracts; the amount of natural gas inventory was approximately $29.0 million and $82.4 million at December 31, 2004 and 2003, respectively. See Note 2 for a further discussion.

Effective December 31, 2003, approximately $20.8 million of natural gas storage inventory that was previously classified as Property, Plant and Equipment used in Enogex Inc.’s business activities was reclassified to Fuel Inventories on the Consolidated Balance Sheet. During the fourth quarter of 2003, Enogex implemented a business process to actively manage seasonal opportunities around the four billion cubic feet previously reserved to manage pipeline system requirements during peak periods. The intent of management is to capture commercial opportunities while maintaining adequate inventory levels necessary to meet ongoing contractual obligations.

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Company’s pipeline system differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in-kind. The Company values all imbalances at average market prices estimated to be in effect at the time the imbalance will be settled. Also, included in Gas Imbalances on the Consolidated Balance Sheets are planned or managed imbalances related to Enogex’s marketing business, referred to as park and loan transactions. Park and loan assets were approximately $76.0 million and $45.4 million, respectively, at December 31, 2004 and 2003 and park and loan liabilities were approximately $2.4 million and $9.7 million, respectively, at December 31, 2004 and 2003. Operational imbalance assets were approximately $24.1 million and $24.6 million, respectively, at December 31, 2004 and 2003 and operational imbalance liabilities were approximately $20.4 million and $12.8 million, respectively, at December 31, 2004 and 2003.

Property, Plant and Equipment

OG&E

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction (“AFUDC”). Replacements of major units of property are capitalized as plant. The replaced plant is removed from plant balances and the cost of such property less salvage is charged to Accumulated Depreciation. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense. Effective January 1, 2003, removal expense has no longer been charged to Accumulated Depreciation but rather has been charged to regulatory liabilities in accordance with SFAS No. 143.

Enogex

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor, materials and overheads used during construction. Replacements of units of property are capitalized as plant. For group assets, the replaced plant is removed from plant balances and charged to Accumulated Depreciation. For non-group assets, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and removal costs are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

The Company’s property, plant and equipment are divided into the following major classes at December 31, 2004 and 2003, respectively.

December 31 (In millions)		2004			2003

OGE Energy Corp. (holding company)
Property, plant and equipment	$	65	.3	$	57	.0

OGE Energy Corp. property, plant and equipment		65	.3		57	.0

OG&E
Distribution assets		1,934	.0		1,834	.7
Electric generation assets		1,828	.3		1,628	.1
Transmission assets		552	.8		536	.9
Intangible plant		6	.3		5	.3
Other property and equipment		313	.0		265	.1

OG&E property, plant and equipment		4,634	.4		4,270	.1

Enogex
Transportation and storage assets		883	.6		879	.9
Gathering and processing assets		483	.1		467	.4
Marketing assets		7	.5		7	.3

Enogex property, plant and equipment		1,374	.2		1,354	.6

Total property, plant and equipment	$	6,073	.9	$	5,681	.7

Depreciation

OG&E

The provision for depreciation, which was approximately 2.9 percent of the average depreciable utility plant for 2004 and 2003, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method.

Enogex

Depreciation is computed principally on the straight-line method using estimated useful lives of three to 83 years for transportation and storage assets, three to 30 years for gathering and processing assets and three to 10 years for marketing assets. Amortization of intangibles other than debt costs is computed using the straight-line method over the respective lives of the intangibles ranging up to 20 years.

Impairment of Assets

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 determined or included in the 2005 earnings guidance.

Allowance for Funds Used During Construction

AFUDC is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. AFUDC, a non-cash item, is reflected as a credit in the Consolidated Statements of Income and as a charge to Construction Work in Progress in the Consolidated Balance Sheets. AFUDC rates, compounded semi-annually, were 4.99 percent, 1.67 percent and 2.40 percent for the years 2004, 2003 and 2002, respectively. The increase in the AFUDC rates in 2004 was primarily due to a portion of capital expenditures being funded by equity funds, which have a higher cost rate than short-term borrowings, which were used to fund capital expenditures in 2003 and 2002.

Revenue Recognition

OG&E

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. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Enogex

The Company recognizes revenue from natural gas gathering, processing, transportation and storage services to third parties as services are provided. Revenue associated with natural gas liquids is recognized when the production is sold. Substantially all of OERI’s natural gas contracts

qualify as derivatives and, therefore, are accounted for at fair value as prescribed in SFAS No. 133. Under fair value accounting, fixed-price forwards, swaps, options, futures and other financial instruments with third parties are recorded at estimated fair market values, net of reserves, with the corresponding market changes in fair value recognized in earnings and offsetting amounts recorded as Price Risk Management assets and liabilities in the Consolidated Balance Sheets. See Note 2 for a further discussion.

The default processing fee, which decreases the volatility of Enogex’s earnings stream by reducing Enogex’s exposure to keep-whole processing arrangements, is implemented in the event the natural gas liquids revenue less the associated fuel and shrinkage costs is negative. The Company records any default processing fees billed to customers as deferred revenue until it becomes probable that the processing gross margin threshold in Enogex’s Statement of Operating Conditions (“SOC”) will not be exceeded. Based on the 2004 processing gross margin, the default processing fees billed to customers in 2004 were recorded as deferred revenue as the 2004 processing gross margin exceeded the 2004 processing gross margin threshold in the SOC.

Automatic Fuel Adjustment Clauses

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses, which 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 proceeding before the OCC in which OG&E is seeking to recover costs billed to it by Enogex for gas transportation and storage services.

Stock-Based Compensation

Pursuant to the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, the Company has not recognized compensation expense for its stock-based awards to employees. See Note 10 for a further discussion related to the Company’s Stock Incentive Plan. Also, see Note 2 for a discussion of a recent accounting pronouncement which replaces SFAS No. 123 that the Company will adopt effective July 1, 2005.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123.” SFAS No. 148 amended the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The following table reflects pro forma net income and income per average common share had the Company elected to adopt the fair value based method of SFAS No. 123:

Year Ended December 31 (In millions, except per share data)		2004			2003			2002


Net income, as reported	$	153.	5	$	129.	8	$	90.	8

Add:
Stock-based employee compensation expense included
in reported net income, net of related tax effects		--	-		--	-		--	-

Deduct:
Stock-based employee compensation expense determined
under fair value based method for all awards, net of
related tax effects

OGE Energy Corp.

Proxy Statement and Notice of Annual Meeting

May 19, 2005

OG+E

Contents

OGE Energy Corp.

Dear Shareowner:

Notice of Annual Meeting of Shareowners

Voting Procedures; Revocation of Proxy

Record Date; Number of Votes

Expenses of Proxy Solicitation

Corporate Governance

Audit Fees

Audit-Related Fees

Tax Fees

All Other Fees

Audit Committee Pre-Approval Procedures

OGE ENERGY CORP.

AUDIT COMMITTEE CHARTER

Purposes

Composition

Duties and Responsibilities

Meetings

Resources and Authority

Audit Committee Report

Annual Review

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

Introduction

Executive Overview

Forward-Looking Statements

Overview

2005 Outlook

Results of Operations

Financial Condition

Off-Balance Sheet Arrangements

Liquidity and Capital Requirements

2004 Capital Requirements and Financing Activities

Fair Value Hedges

Cash Flow Hedges

Future Capital Requirements

Security Ratings

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Quantitative and Qualitative Disclosures About Market Risk.

Fair Value Hedges

Cash Flow Hedges

Financial Statements and Supplementary Data.

OGE ENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME

OGE ENERGY CORP. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

OGE ENERGY CORP. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

OGE ENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS

OGE ENERGY CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization

Accounting Records

Use of Estimates

Cash and Cash Equivalents

Allowance for Uncollectible Accounts Receivable

Fuel Inventories

Gas Imbalances

Property, Plant and Equipment

Depreciation

Impairment of Assets

Allowance for Funds Used During Construction

Revenue Recognition

Automatic Fuel Adjustment Clauses

Stock-Based Compensation

Proxy Statement
and
Notice of Annual Meeting

Notice of Annual Meeting
of Shareowners

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

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS

OGE ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS