Contents

	Page

Chairman’s Letter	ii	Notice of Annual Meeting of Shareowners
		and Proxy Statement
Notice of Annual Meeting of Shareowners	iii

Proxy Statement	1	Thursday, May 22, 2008, at 10:00 a.m.

Proposal No. 1 – Election of Directors	3	National Cowboy and Western Heritage Museum
		1700 Northeast 63rd Street
Information Concerning the Board of Directors	7	Oklahoma City, Oklahoma

Proposal No. 2 – Ratification of Ernst &	14
Young LLP as Company’s Principal
Independent Accountants

Report of Audit Committee	15

Executive Officers’ Compensation	17
Compensation Discussion and Analysis	17
Summary Compensation Table	26
Grants of Plan-Based Awards Table	27
Outstanding Equity Awards at Fiscal	28
Year-End Table
Option Exercises and Stock Vested Table	29
Pension Benefits Table	29
Nonqualified Deferred Compensation Table	31
Compensation Committee Report	32
Potential Payments upon Termination or	33
Change of Control

Security Ownership	35

Equity Compensation Plan Information	36

Proposal No. 3 – Approval of OGE Energy Corp.	36
2008 Stock Incentive Plan

Proposal No. 4 – Approval of OGE Energy Corp.	41
2008 Annual Incentive Compensation Plan

Proposal No. 5 – Shareowner Proposal to Eliminate	45
Classification of the Terms of the Directors

Section 16(a) Beneficial	47
Ownership Reporting Compliance

Householding Information	47

Map	48

Annex A - 2008 Stock Incentive Plan	A-1
Annex B - 2008 Annual Incentive Compensation Plan	B-1

Appendix A – 2007 Financial Statements
and Management’s Discussion and Analysis

(i)

OGE Energy Corp.

	April 2, 2008
Dear Shareowner: You are cordially invited to attend the annual meeting of OGE Energy Corp. at 10:00 a.m. on Thursday, May 22, 2008, 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 greatly 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/ Peter B. Delaney Peter B. Delaney Chairman of the Board, President and Chief Executive Officer

(ii)

Notice of Annual Meeting of Shareowners


The Annual Meeting of Shareowners of OGE Energy Corp. will be held on Thursday, May 22, 2008, 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;
(2)	To ratify the appointment of Ernst & Young LLP as our principal independent accountants;
(3)	To approve the OGE Energy Corp. 2008 Stock Incentive Plan;
(4)	To approve the OGE Energy Corp. 2008 Annual Incentive Compensation Plan;
(5)	To consider a shareowner proposal to eliminate the classification of the terms of the directors, if properly presented; and
(6)	To transact such other business as may properly come before the meeting.


The map on page 48 will assist you in locating the National Cowboy and Western Heritage Museum. Shareowners who owned stock on March 24, 2008, 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 Vice President – Administration and Corporate Secretary
Dated: April 2, 2008
IMPORTANT — YOUR PROXY CARD IS ENCLOSED IN THIS ENVELOPE

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

(iii)

Proxy Statement

April 2, 2008

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 22, 2008, at 10:00 a.m. For the convenience of those shareowners who may attend the meeting, a map is printed on page 48 that gives directions to the National Cowboy and Western Heritage Museum. At the meeting, we intend to present the first five items in the accompanying notice for action by the owners of the Company’s Common Stock. The Board of Directors does not now know of any other matters to be presented at the meeting, but, if any other matters are properly presented to the meeting for action, the persons named in the accompanying proxy will vote upon them in accordance with their best judgment.

Your Board of Directors is sending you this proxy statement in connection with the solicitation of your proxy for use at the Annual Meeting. When you vote by Internet, by telephone or by mail, you appoint Peter B. Delaney, Luke R. Corbett and Robert Kelley as your representatives at the Annual Meeting. Mr. Delaney, Mr. Corbett 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. Delaney, Mr. Corbett 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, FOR the ratification of Ernst & Young LLP as the Company’s principal independent accountants, FOR approval of the OGE Energy Corp. 2008 Stock Incentive Plan, FOR approval of the OGE Energy Corp. 2008 Annual Incentive Compensation Plan and AGAINST the shareowner proposal to eliminate the classification of the terms of the directors.

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

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

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

Record Date; Number of Votes

If you owned shares of our Common Stock at the close of business on March 24, 2008, you are entitled to one vote per share upon each matter presented at the meeting.

On March 1, 2008, there were 91,973,891 shares of Common Stock outstanding. The Company does not have any other outstanding class of voting stock. Other than as described below under the heading “Security Ownership,” 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 BNY Mellon Shareowner Services to assist in the solicitation of proxies, at a fee of approximately $10,000 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 April 2, 2008. 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. Delaney’s letter to shareowners, condensed financial statements and a summary discussion of results of operations, were mailed with this proxy statement on or about April 2, 2008, to all of our shareowners who owned stock on March 24, 2008.

Important Notice Regarding the Availability of Proxy Materials for the Shareowner Meeting To Be Held on May 22, 2008.

The proxy statement, including Appendix A that includes our audited financial statements and management’s discussion and analysis of financial condition and results of operations, and our Summary Annual Report is available at: http://bnymellon.mobular.net/bnymellon/oge.

The Annual Meeting of Shareowners of the Company will be held at the National Cowboy and Western Heritage Museum, 1700 Northeast 63rd Street, Oklahoma City, Oklahoma, on May 22, 2008, at 10:00 a.m.

The matters to be voted upon are:

(1)

The election of three directors;

(2)

The ratification of the appointment of Ernst & Young LLP as our principal independent accountants;

(3)

The approval of the OGE Energy Corp. 2008 Stock Incentive Plan;

(4)

The approval of the OGE Energy Corp. 2008 Annual Incentive Compensation Plan;

(5)

The consideration of a shareowner proposal to eliminate the classification of the terms of the directors, if properly presented; and

(6)

The transaction of such other business as may properly come before the meeting.

The Board of Directors recommends a vote FOR the three named nominees for director, FOR the ratification of Ernst & Young LLP as the Company’s principal independent accountants, FOR approval of the OGE Energy Corp. 2008 Stock Incentive Plan, FOR approval of the OGE Energy Corp. 2008 Annual Incentive Compensation Plan and AGAINST the shareowner proposal to eliminate the classification of the terms of the directors.

The following materials are available at http://bnymellon.mobular.net/bnymellon/oge :

(1)

Notice of Annual Meeting

(2)

Proxy Statement, including Appendix A that includes our audited financial statements and management’s discussion and analysis of financial condition and results of operations.

(3)

Summary Annual Report

Your proxy card will contain an identification number that you can use to vote by telephone or over the Internet.

For the convenience of those shareowners who may attend the meeting, a map is printed on page 48 that gives directions to the National Cowboy and Western Heritage Museum.

Voting Under Plans

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

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

Voting of Shares Held in Street Name by Your Broker

If your shares are held in a stock brokerage account or by a bank or other nominee, you are considered the beneficial owner of shares held in street name and these proxy materials are being forwarded to you by your broker or nominee who is considered, with respect to those shares, the shareowner of record. As the beneficial owner, you have the right to direct your broker on how to vote your shares. You are also invited to attend the Annual Meeting and vote your shares in person. In order to vote your shares in person, you must provide us with a legal proxy from your broker.

Brokerage firms have authority under New York Stock Exchange Rules to vote customers’ shares for which they have not received voting instructions on certain “routine” matters, including the election of directors and ratification of the auditors. If you do not provide voting instructions, 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. 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, such as the proposals to approve the OGE Energy Corp. 2008 Stock Incentive Plan and the OGE Energy Corp. 2008 Annual Incentive Compensation Plan and the shareowner proposal. 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.

In order for your shares to be voted on all matters presented at the meeting, we urge all shareowners whose shares are held in street name by a brokerage firm to provide voting instructions to the brokerage firm.

PROPOSAL NO. 1 -

ELECTION OF DIRECTORS

The Board of Directors of the Company is classified into three groups that are to be as equal in number as possible. 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 Board presently consists of 11 members; however, Mr. Herbert H. Champlin and Dr. Ronald H. White will retire from the Board effective at the Annual Meeting. The following three persons are the nominees of the Board to be elected for a three-year term at the Annual Meeting to be held on May 22, 2008: Mr. Kirk Humphreys, Ms. Linda Petree Lambert and Mr. Leroy Richie. Each of these individuals nominated for election at the Annual Meeting is currently a director of the Company. In addition, each of these individuals, as well as each other director of the Company during 2007, also was a director of the Company’s principal subsidiary, Oklahoma Gas and Electric Company (“OG&E”).

As discussed above, Mr. Champlin and Dr. White will retire from the Board effective at the Annual Meeting. Mr. Champlin has served as a director of OG&E since 1982 and as a director of OGE Energy since its inception in 1996. Dr. White has served as a director of OG&E since 1989 and as a director of OGE Energy since its inception in 1996. The Board of Directors expresses its sincere appreciation and thanks to Mr. Champlin and Dr. White for their 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 0.3% 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.

INFORMATION ABOUT DIRECTORS AND NOMINEES

The following contains certain information as of March 1, 2008, concerning the three nominees for director, as well as the directors whose terms of office extend beyond the Annual Meeting on May 22, 2008.

Nominees for Election for Term Expiring at 2011 Annual Meeting of Shareowners

KIRK HUMPHREYS, 57, is the Chairman and Manager of Humphreys Real Estate Investments, LLC. He has been active in the development and acquisition of commercial real estate in Oklahoma and surrounding states. He was elected Mayor of Oklahoma City in 1998 and re-elected in 2002. Mr. Humphreys serves as vice chairman for Aviation and Aerospace of the Greater Oklahoma City Chamber of Commerce and the chairman of the Oklahoma District Council of the Urban Land Institute. He is a trustee of the Oklahoma City Airport Trust, the Oklahoma City Economic Development Trust and the Oklahoma Industries Authority. He serves on the boards of the Oklahoma State Fair, INTEGRIS Health and City Care. Mr. Humphreys has been a director of the Company and of OG&E since November 2007, and is a member of the compensation committee and the audit committee of the Board.

PHOTO

LINDA PETREE LAMBERT, 68, is President of LASSO Corporation, a diversified oil and gas investment company, and President of Enertree, L.L.C., also an oil and gas investment company. Ms. Lambert also serves as Chairman of the Board of Mercy Health Center and a member of the Board of Directors of InvesTrust, a privately held trust company, Oklahoma Water Resource Board, Oklahoma City Public Schools Trust, International Longevity Center, the Oklahoma National Memorial Foundation and the United Way of Central Oklahoma. Ms. Lambert has been a director of the Company and of OG&E since November 2004, and is a member of the audit committee and the nominating and corporate governance committee of the Board.

PHOTO

LEROY C. RICHIE, 66, serves as of counsel to the Detroit-based law firm of Lewis & Munday, P.C., one of the oldest and largest law firms in the nation founded by minorities. From 1998 to 2004, Mr. Richie was chairman and CEO of Q Standards World Wide Inc. and Capitol Coating Technologies Inc., and President of Intrepid World Communications. Mr. Richie also has served as Vice President and General Counsel for Automotive Legal Affairs of Chrysler Corporation and as director of the New York office of the Federal Trade Commission. Mr. Richie served on the Board of Directors of Kerr-McGee Corporation from 1998 to 2006, the last three years as chairman of the Audit Committee. He currently serves as a director of Digital Ally Inc., Infinity Energy Resources Inc., Vibration Control Technologies, LLC, Great Lakes Assemblies, LLC, Gulf Shore Assemblies, LLC and companies in the Seligman family of investment companies. Mr. Richie has been a director of the Company and of OG&E since November 2007, and is a member of the compensation committee and the nominating and corporate governance committee of the Board.

PHOTO

Directors Whose Terms Expire at 2010 Annual Meeting of Shareowners

LUKE R. CORBETT, 61, is the former Chairman and Chief Executive Officer of Kerr-McGee Corporation, which engaged in oil and gas exploration and production and chemical operations. He had been employed by Kerr-McGee Corporation for more than 17 years prior to his retirement from Kerr-McGee Corporation on September 1, 2006, 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 Anadarko Petroleum Corporation, which acquired Kerr-McGee Corporation on September 1, 2006. Mr. Corbett has been a director of the Company and OG&E since December 1996. He serves as Lead Director of the Board and is chairman of the compensation committee.

PHOTO

PETER B. DELANEY, 54, is Chairman, President and Chief Executive Officer of the Company and OG&E. From January 2007 until September 2007, Mr. Delaney was President and Chief Operating Officer of the Company and OG&E. From 2004 to January 2007 he was Executive Vice President and Chief Operating Officer of the Company and OG&E. From 2002 to 2004, Mr. Delaney was Executive Vice President, Finance and Strategic Planning for the Company and has served since 2002 as the Chief Executive Officer of the Company’s Enogex Inc. subsidiary. Mr. Delaney has been a director of the Company and OG&E since January 2007. Mr. Delaney also serves as Chief Executive Officer and a director of OGE Enogex GP LLC, an affiliate of the Company.

PHOTO

J. D. WILLIAMS, 70, 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 and having retired as an employee of the firm in December 2004. He has agreed to make himself available as an independent contractor to provide limited services to the firm through December 31, 2010. Mr. Williams is involved in various civic and related matters. 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 and is a member of the compensation committee of the Board.

PHOTO

Directors Whose Terms Expire at 2009 Annual Meeting of Shareowners

JOHN D. GROENDYKE, 63, is Chairman of the Board and Chief Executive Officer of Groendyke Transport Inc., a bulk truck transportation company in Enid, Oklahoma. Mr. Groendyke has worked at Groendyke Transport, Inc. since 1965. Mr. Groendyke also serves in various capacities at subsidiaries of Groendyke Transport, Inc., including Chairman of the Board and President of Bell Transport, Inc.; Oringderrf Tank Line, Inc.; Transport Company, Inc. and Triple “A” Transport and 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 & Trust Co. 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.

PHOTO

ROBERT KELLEY, 62, 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 Cabot Oil and Gas Corporation and Smith International, Inc. 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 and OG&E since December 1996, and is chairman of the audit committee and is a member of the compensation committee of the Board.

PHOTO

ROBERT O. LORENZ, 61, is a retired partner of the Arthur Andersen accounting firm. Mr. Lorenz joined Arthur Andersen in 1969, became a partner in 1982 and was named managing partner of the Oklahoma City office in 1994 and was named managing partner of the Oklahoma practice in 2000, the position he held until November 2002, when he retired. Mr. Lorenz serves on the Board of Directors and audit committees of Panhandle Oil and Gas, Inc., Infinity Energy Resources, Inc., and OGE Enogex GP LLC, an affiliate of the Company. Mr. Lorenz also is on the Board of Directors of the United Way of Central Oklahoma. Mr. Lorenz served on the Board of Directors of Kerr-McGee Corporation until September 1, 2006 when Kerr-McGee was acquired by Anadarko Petroleum Corporation. Mr. Lorenz has been a director of the Company and OG&E since July 2005, and is a member of the audit committee and the nominating and corporate governance committee of the Board.

PHOTO

The affirmative vote of the holders of a majority of the shares of Common Stock present in person or by proxy and entitled to vote at the Annual Meeting will be required for the election of the 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

General. Each member of our Board of Directors was also a director of OG&E during 2007. The Board of Directors of the Company and OG&E met on nine occasions during 2007. Each director attended at least 92% of the total number of meetings of the Boards of Directors and the committees of the Boards on which he or she served.

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

The members of these committees during 2007 and 2008, the general functions of the committees and number of committee meetings in 2007, are set forth below.

Name of Committee and Members	General Functions of the Committee	Number of Meetings in 2007

Compensation Committee: Herbert H. Champlin Luke R. Corbett* John D. Groendyke Kirk Humphreys Robert Kelley Leroy C. Richie Ronald H. White, M.D. J. D. Williams	Oversees • compensation of directors and principal officers • executive compensation policy • benefit programs	9

Audit Committee: Herbert H. Champlin Luke R. Corbett Kirk Humphreys Robert Kelley* Linda Petree Lambert Robert O. Lorenz	Oversees financial reporting process • evaluate performance of independent auditors • select independent auditors • discuss with internal and independent auditors scope and plans for audits, adequacy and effectiveness of internal controls for financial reporting purposes, and results of their examinations • review interim financial statements and annual financial statements to be included in Form 10-K	6

Nominating and Corporate Governance Committee: John D. Groendyke Linda Petree Lambert Robert O. Lorenz Leroy C. Richie Ronald H. White, M.D. J. D. Williams*	Reviews and recommends • nominees for election as directors • membership of director committees • succession plans • various corporate governance issues	10


* Chairperson

Corporate Governance

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

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

The Guidelines provide that the Compensation Committee of the Board will evaluate the performance of the CEO on an annual basis and that the Nominating and Corporate Governance Committee will report to the Board at least annually on succession planning, which will include appropriate contingencies in the event the CEO retires or is incapacitated. The Guidelines also provide that the Nominating and Corporate Governance Committee is responsible for overseeing an annual assessment of the performance of the Board and Board committees, as well as for reviewing with the Board the results of these assessments. All of these tasks were completed for 2007.

The Guidelines provide that Board members have full access to officers and employees of the Company and, as necessary and appropriate, the Company’s independent advisors, including legal counsel and independent accountants. The Guidelines further provide that the Board and each committee have the power to hire independent legal, financial or other advisors as they deem necessary. The Guidelines provide that the independent directors, which include all non-management directors, are to meet in executive session, generally coinciding with regularly scheduled Board meetings. In 2007, the independent directors met in executive session eight times.

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

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

•

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;

•

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;

•

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 judgment as a director.

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

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

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

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

•

review and approve corporate goals and objectives relevant to the compensation of the CEO and other executive officers

•

evaluate the performance of the CEO and the other executive officers in light of the corporate goals and objectives and set compensation levels for the executive officers

•

recommend to the Board the approval, adoption and amendment of all incentive compensation plans in which any executive officer participates and all other equity-based plans

•

administer the equity-based incentive compensation plans and any other plans adopted by the Board that contemplate administration by the Compensation Committee

•

approve all grants of stock options and other equity-based awards

•

review and approve employment, severance or termination arrangements for any executive officers

•

review Board compensation

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

The process for setting director and executive compensation in 2007 involved numerous steps. In 2006, senior management met with representatives of Towers Perrin, a nationally recognized compensation consulting firm engaged by the Compensation Committee, to discuss the Company’s existing executive compensation program and potential changes to the program or any of the underlying compensation plans. In 2006, the Company’s Board of Directors received a report from Towers Perrin that included an annual review of director and executive compensation in the utility industry and an overview of trends and emerging issues in executive and board remuneration.

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

The balance of the process for setting director and executive compensation for 2007 involved actions taken by the Compensation Committee. The Compensation Committee met in November 2006, February 2007 and March 2007 to address 2007 compensation. At the November 2006 meeting, the Compensation Committee reviewed with the CEO and COO the performance evaluations of each member of management (other than the CEO), with the CEO giving his performance evaluation of the COO. The Compensation Committee at its November 2006 meeting also reviewed and discussed with the CEO and COO their recommendations for each member of management (other than the CEO) of 2007 salaries, target annual incentive awards (expressed as a percentage of salary) and target long-term incentive awards (also expressed as a percentage of salary). In addition, the Compensation Committee evaluated the CEO’s performance at its November 2006 meeting and discussed his potential salary, target annual incentive award and target long-term compensation for 2007. Following these discussions, the Compensation Committee set 2007 salaries and, subject to potential adjustment at its meeting in February 2007, target annual incentive awards and target long-term compensation awards for each member of management. The target annual incentive awards and target long-term compensation awards were expressed as percentages of salary. The Company performance goals that needed to be achieved for any payouts of annual incentive awards or long-term incentives were not set at this meeting; but, instead, were left for consideration at the scheduled

meeting in February 2007. At its meeting in November 2006, the Compensation Committee also reviewed and set compensation for the directors, which is described below under “Director Compensation.”

Prior to the Compensation Committee’s meeting in February 2007, the Company’s senior management developed recommendations for the Company performance goals that needed to be met in order for any payouts of 2007 annual incentive awards or 2007 long-term compensation awards to occur.

At the Compensation Committee’s meeting in February 2007, the Committee reviewed with senior management its recommendations and basis for Company performance goals for payouts of 2007 annual incentive awards and long-term compensation awards. Following this discussion, the Compensation Committee set the 2007 Company performance goals for annual incentive awards and long-term compensation awards that had to be achieved in order for payouts of such awards to occur. The Compensation Committee also approved the form of the long-term compensation awards, which, like prior years, consisted entirely of performance units. However, the Compensation Committee at the meeting in February 2007 decided to defer granting the performance units as the Compensation Committee wanted more information on the valuation of the performance units for the purpose of determining the number of performance units to be granted. Specifically, the Compensation Committee wanted more information on the methodology being recommended for valuing the performance units, which involved discounting the value of a performance unit from the price of a share of the Company’s Common Stock for such items as non-payment of dividends during the three-year performance period and risk of forfeiture. At a meeting, on March 7, 2007, the requested information was presented to the Compensation Committee and the Compensation Committee decided to value the performance units based entirely on a recent price of the Company’s Common Stock without any discounting and directed management and Towers Perrin to provide the Compensation Committee with new market data for executive officers calculated without regard to any discounts. This new market data was presented to the Compensation Committee at a meeting on March 14, 2007, at which time the Compensation Committee specified the percentage of an officer’s salary to be paid in long-term incentives and, based on the closing price of the Company’s Common Stock on March 13, 2007, the precise number of performance units to be granted. The overall effect of the elimination of discounts in valuing performance units was to decrease slightly the number of performance units granted.

Following Mr. Moore’s death in September 2007, Mr. Peter Delaney was appointed as Chairman of the Board and CEO to succeed Mr. Moore. Mr. Delaney previously had served as President and Chief Operating Officer of the Company. Also, Mr. Danny Harris, formerly the Company’s Senior Vice President – Unregulated Business, was appointed Senior Vice President and Chief Operating Officer of the Company. At the Compensation Committee’s meeting on October 16, 2007, the Compensation Committee increased the annual salaries, effective as of October 1, 2007, of Mr. Delaney from $531,000 to $775,000 and of Mr. Harris from $305,000 to $510,000 in recognition of their increased level of responsibilities. No change was made to other components of their compensation.

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 non-management lead director chairs executive sessions of the Board conducted without management. These sessions will be held at least twice annually and were held eight times in 2007.

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

The Company encourages each of its Board members to attend the Annual Meeting and the directors are expected to attend whenever reasonably possible. All of the Board members attended the Annual Meeting in 2007.

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

Auditors; Audit Partner Rotation. As described on page 14, the Company is requesting that the shareowners ratify the selection of Ernst & Young LLP as the Company’s principal independent accountants for 2008. The Audit Committee charter provides that the audit partners will be rotated as required by the Sarbanes-Oxley Act of 2002.

Stock Ownership Guidelines. During 2004, the Company established stock ownership guidelines for its directors and officers. These guidelines were reviewed and revised by the Compensation Committee in 2008. The terms of these guidelines are explained on page 25 in Compensation Discussion and Analysis.

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

In considering individuals for nomination as directors, the nominating and corporate governance committee typically solicits recommendations from its current directors and is authorized to engage third party advisors, including search firms, to assist in the identification and evaluation of candidates. Mr. Kirk Humphreys and Mr. Leroy Richie were elected to the Board in November 2007. Mr. Humphreys and Mr. Richie were recommended by current directors of the Company.

The nominating and corporate governance committee has not established specific minimum qualities for director nominees or set forth specific qualities or skills that the nominating and corporate governance committee believes are necessary for one or more directors to possess. Instead, in evaluating potential candidates and incumbent directors for reelection, the nominating and corporate governance committee considers numerous factors, including judgment, skill, independence, integrity, experience with businesses and other organizations of comparable size, the interplay of the candidate’s experience with the experience of other Board members, experience as an officer or director of another publicly-held corporation, understanding of management trends in general or in industries relevant to the Company, expertise in financial accounting and corporate finance, ability to bring diversity to the group, community or civic service, appropriateness of having a member of management, in addition to the CEO, on the Board as part of the succession planning process, knowledge or expertise not currently on the Board, shareowner perception, and the extent to which the candidate would be a desirable addition to the Board and any committees of the Board. No particular weight is given to one factor over another on a general basis, but rather the factors are weighted in relationship to the perceived needs of the Board at the time of selecting nominees. The nominating and corporate governance committee will evaluate candidates recommended by shareowners on the same basis as they evaluate other candidates.

Director Compensation. Compensation of non-officer directors of the Company during 2007 included an annual retainer fee of $86,000, of which $2,500 was payable monthly in cash and $56,000 was deposited in the director’s account under the Company’s Deferred Compensation Plan in December 2007 and converted to 1,573.034 common stock units based on the closing price of the Company’s Common Stock on November 30, 2007. All non-officer directors received $1,200 for each Board meeting and $1,200 for each committee meeting attended. The lead director and the chairman of the audit committee received an additional $10,000 cash retainer. The chairmen of the compensation and nominating and corporate governance committees received an additional $5,000 annual cash retainer in 2007. Each chairman of a board committee also received a meeting fee of $1,200 for each meeting (either in person or by phone) with management to address committee matters. Each member of the audit committee also received an additional annual retainer of $5,000. These amounts represent the total fees paid to directors in their capacities as directors of the Company and OG&E during 2007. In addition, for his service on the board of directors of OGE Enogex GP LLC, Mr. Lorenz received an additional amount of $2,917 from OGE Enogex GP LLC representing his pro rata portion of the $35,000 annual cash retainer for non-employee directors of OGE Enogex GP LLC.

Under the Company’s Deferred Compensation Plan, non-officer directors may defer payment of all or part of their attendance fees and the cash portion of their annual retainer fee, which deferred amounts are credited to their account as of the first day of the month in which the deferred amounts otherwise would have been paid. Amounts credited to the accounts are assumed to be invested in one or more of the investment options permitted under the Company’s Deferred Compensation Plan. During 2007, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company’s Common Stock, a money market fund, a bond fund and several stock funds. When an individual ceases to be a director of the Company, all amounts credited under the Company’s Deferred Compensation Plan are paid in cash in a lump sum or installments as provided in the Deferred Compensation Plan. As described under “Executive Officers’

Compensation – Nonqualified Deferred Compensation Table,” in certain circumstances, participants may also be entitled to in-service withdrawals from the Deferred Compensation Plan.

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

Director Compensation

Name		Fees Earned or Paid in Cash ($)	Stock Awards ($)(1)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
(a)		(b)	(c)	(d)	(e)	(f)	(g)	(h)
Herbert H. Champlin		$65,000	$56,000	0	0	0	0	$121,000
Luke R. Corbett		$92,000	$56,000	0	0	0	0	$148,000
John D.Groendyke		$66,000	$56,000	0	0	0	0	$122,000
Kirk Humphreys		$7,400	$56,000	0	0	0	0	$63,400
Robert Kelley		$79,800	$56,000	0	0	0	0	$135,800
Linda Petree Lambert		$65,000	$56,000	0	0	0	0	$121,000
Robert O. Lorenz		$68,600	$56,000	0	0	0	0	$124,600
Leroy C. Richie		$7,400	$56,000	0	0	0	0	$63,400
Ronald H. White, M.D.		$64,800	$56,000	0	0	0	0	$120,800
J.D. Williams		$77,000	$56,000	0	0	0	0	$133,000
(1)	Amounts in this column represent the dollar value of the annual retainer that was deposited in the director’s account under the Directors’ Deferred Compensation Plan. As of December 31, 2007, the number of common stock units in the Company Common Stock Fund for each of the directors was as follows: Mr. Champlin, 58,039 common stock units; Mr. Corbett, 42,005 common stock units; Mr. Groendyke, 12,415 common stock units; Mr. Humphreys, 1,573 common stock units; Mr. Kelley, 37,456 common stock units; Ms. Lambert, 6,829 common stock units; Mr. Lorenz, 8,469 common stock units; Mr. Richie, 1,573 common stock units; Dr. White, 45,332 common stock units; and Mr. Williams, 12,522 common stock units.

PROPOSAL NO. 2 -

RATIFICATION OF THE APPOINTMENT OF ERNST & YOUNG LLP AS THE COMPANY’S PRINCIPAL INDEPENDENT ACCOUNTANTS FOR 2008

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, 2008. Ernst & Young LLP was originally selected by the Board, upon the recommendation of the Audit Committee, as principal independent accountants for the Company effective May 16, 2002.

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

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

The affirmative vote of the holders of a majority of the votes of shares of Common Stock present in person or by proxy and entitled to vote at the Annual Meeting will be required for the ratification of the appointment of Ernst & Young LLP as the Company’s principal independent accountants for 2008. 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 five members, none of whom has any relationship to the Company that interferes with the exercise of his or her independence from management and the Company, and each of whom qualifies as independent under the standards used by the New York Stock Exchange, where the Company’s shares are listed. The Audit Committee operates under a written charter that has been approved by the Board of Directors. The Audit Committee annually reviews and reassesses the adequacy of its charter. Among other things, the charter specifies the policies for selecting the auditors (including rotation for the audit partner) and the scope of the Audit Committee’s responsibilities and how it carries out those responsibilities, including structure, processes and membership requirements.

In fulfilling its oversight responsibilities regarding the 2007 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 2007 financial statements and management’s assessment of the Company’s internal control over financial reporting. The Company’s independent auditors are responsible for expressing an opinion on the conformity of our audited financial statements with accounting principles generally accepted in the United States and on the Company’s internal control over financial reporting. Our review with the independent auditors included a discussion of the auditors’ judgments as to the quality, not just the acceptability, of the Company’s accounting principles and such other matters as are required to be discussed with the Audit Committee under Statement on Auditing Standards No. 61, as amended. In addition, the Audit Committee discussed with the independent auditors the auditors’ independence from management and the Company, including the matters in the written disclosures received by the Audit Committee pursuant to Rule 3600T of the Public Company Accounting Oversight Board.

The Audit Committee also discussed with the Company’s internal and independent auditors the overall scope and plans for their respective audits for 2008. 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 2007 and the Chairman of the Audit Committee conducted one conference with management by telephone to discuss Audit Committee matters.

Fees for Independent Auditors

Audit Fees

Total audit fees for 2007 were $2,302,000 for the Company’s 2007 financial statement audit. These fees include $595,000 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $332,000 for services in support of debt and stock offerings. Total audit fees for 2006 were $1,996,069 for the Company’s 2006 financial statement audit. These fees include $682,669 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $15,750 for services in support of debt and stock offerings.

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 2007, this amount includes estimated billings for the completion of the 2007 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, 2007 were $112,000, of which $94,500 was for employee benefit plan audits and $17,500 for other audit-related services.

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

Tax Fees

The aggregate fees billed for tax services for the fiscal year ended December 31, 2007 were $363,590. These fees include $160,765 for tax preparation and compliance ($65,960 for the review of federal and state tax returns and $94,805 for assistance with examinations and other return issues) and $202,825 for other tax services.

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

All Other Fees

There were no other fees billed to the Company in 2007 or 2006 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, 2007, for filing with the SEC. The Audit Committee selected Ernst & Young LLP as the Company’s independent public accountants for 2008.

Audit Committee Pre-Approval Procedures

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

For 2007, 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*

Kirk Humphreys, Member**

Linda Petree Lambert, Member

Robert O. Lorenz, Member

* Mr. Corbett was a member until November 2007

** Mr. Humphreys was a member only for February 2008 meeting

EXECUTIVE OFFICERS’ COMPENSATION

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

COMPENSATION DISCUSSION AND ANALYSIS

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

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

Our executive compensation program recognizes that our senior executives are in a position to influence directly the Company’s achievement of targeted results and strategic initiatives. For this reason, as an individual’s position and responsibilities increase, a greater portion of the officer’s compensation is at risk and consists of performance-based pay dependent on the achievement of performance objectives. This is shown by the level of salaries, annual incentive awards and long-term incentive awards set for our six most highly paid executive officers in 2007. For each of these executive officers, salary represented less than 55% of the potential amount that could be received through achievement, at target level, of the Company performance goals set in connection with the officer’s annual and long-term incentive awards. As a result, our executive compensation program is designed to reward executives with a highly-competitive level of compensation during years of excellent Company performance and, conversely, in years of below-average performance, their compensation may be below competitive levels.

In an effort to measure the continued reasonableness and competitiveness of our executive compensation policies, the Committee in 2006 followed its past practice and engaged Towers Perrin, a nationally recognized compensation consulting firm, to help survey the marketplace. In setting base salaries and making annual and long-term incentive awards for 2007, the Committee considered the salaries and annual and long-term incentive awards for executives with similar duties at the 50th percentile within the following three groups: (i) Towers Perrin’s 2006 Energy Services Industry Executive Compensation Database (the “Energy Services Survey Group”), consisting of approximately 94 energy services organizations, (ii) Towers Perrin’s 2006 General Industry Executive Compensation Database (the “General Industry Survey Group”), consisting of more than 800 companies in general industries and (iii) the average of the Energy Services Survey Group and the General Industry Survey Group (the “Blended Industry Survey Group”). As the name implies, the Energy Services Survey Group includes energy companies, many of them with significant utility operations, and includes companies with annual revenues ranging from $200 million to $17 billion, with a median of $2.6 billion. The General Industry Survey Group includes many of the same companies from the Energy Services Survey Group as well as companies from the manufacturing, technology, retail, communication, auto and pharmaceutical industries. The companies in this survey group have annual revenues ranging from $300 million to $82 billion, with a median of $5.8 billion. All compensation data from these surveys was size-adjusted so that it would compare to the Company’s or a subsidiary’s projected 2007 revenues, as appropriate, and was updated using a 3.75 percent update factor to reflect anticipated 2007 compensation levels.

Compensation to be paid at the 50th percentile to an executive in the General Industry Survey Group is typically higher, often significantly higher, than the compensation that would be paid to an executive with similar duties in the Energy Services Survey Group. This difference is largely attributable to higher compensation being paid in general industry as compared to the utility industry, which, as noted above, comprises a significant portion of the Energy Services Survey Group. The Committee also received compensation data from Towers Perrin for two other survey groups on salary and annual and long-term awards for executives with similar duties at the 50th percentile of such survey groups. However, the information from these survey groups was not used in any significant way in setting executive compensation. Rather, the information was used primarily to check the reasonableness of the amounts being reported in the General Industry Survey Group and the Blended Industry Survey Group.

While the information from the Energy Services Survey Group, the General Industry Survey Group and the Blended Industry Survey Group are reviewed by our senior management in making recommendations to the Committee and by the Committee in making compensation decisions, both management and the Committee have utilized, where appropriate, the Blended Industry Survey Group as their primary guide in evaluating the competitiveness of the Company’s base salary, target annual incentive awards and target long-term incentive awards for executive officers. The rationale for utilizing the blended industry data has been to:

•

Facilitate the Company’s ability to attract and retain key executive talent with the desired skills sets and

ranges of experience from both inside and outside the traditional utility industry;

•

Acknowledge the Company’s business mix between utility and non-utility assets; and

•

Be consistent with the approach used by similar companies in the industry.

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

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

The Committee met in November 2006 and set each executive officer’s 2007 salary and, subject to potential adjustment at its meeting in February 2007, each executive officer’s target annual incentive award and target long-term incentive award for 2007 based primarily on the individual’s annual performance evaluation and on the comparable amounts shown at the 50th percentile for an executive officer with similar duties in the Blended Industry Group or, in the case of an executive officer whose responsibilities are limited to utility operations, in the Energy Services Survey Group. The target annual and long-term incentive awards were expressed as percentages of salary. While the setting of the target annual incentive and long-term incentive awards is an important part of the executive compensation process, another critical part is the setting of the Company performance goals for such awards. This is a critical part because the level of achievement of the Company performance goals will determine the amount, if any, of the possible payouts of the target annual and long-term incentive awards.

Following a discussion of recommendations by the CEO and COO, the Committee, at its meeting in February 2007, set the Company performance goals for annual incentive and long-term incentive awards. These Company performance goals for executive officers are described in detail below and were intended to align the executive’s interests with our shareowners by having achievement of Company performance goals be directly beneficial to our shareowners. The Committee also approved in substance the form of the long-term compensation awards, which, like recent prior years, were equity-based, consisted entirely of performance units and whose payout was dependent on the Company’s achievement of specified performance goals during the three-year period ending

December 31, 2009. The Committee chose to take these actions at its meeting in February 2007 because the Committee wanted to know the Company’s audited 2006 financial results before setting many of the 2007 performance goals and such audited financial results were not available until shortly before the meeting. However, the Committee at the meeting in February 2007 decided to defer granting the performance units as the Committee wanted more information on the valuation of the performance units for the purpose of determining the number of performance units to be granted. Specifically, the Committee wanted more information on the methodology being recommended for valuing the performance units, which involved discounting the value of a performance unit from the price of a share of the Company’s Common Stock for such items as non-payment of dividends during the three-year performance period and risk of forfeiture. At a meeting on March 7, 2007, the requested information was presented to the Committee and the Committee decided to value the performance units based entirely on a recent price of the Company’s Common Stock without any discounting and directed management and Towers Perrin to provide the Committee with new market data for executive officers on long-term incentives calculated without regard to any discounts. This new market data was presented to the Committee at a meeting on March 14, 2007, at which time the Committee specified the percentage of an officer’s salary to be paid in long-term incentives and, based on the closing price of the Company’s Common Stock on March 13, 2007, the precise number of performance units to be granted. The overall effect of the elimination of discounts in valuing performance units was to decrease slightly the number of performance units granted.

In setting the executive compensation for any given year, the Committee historically (including 2007) has not looked to compensation earned by executives in prior years, including specifically amounts realized from grants in prior years of annual incentive awards or long-term incentive awards. The primary reasons are that our executive compensation program seeks to have all components of executive compensation be competitive, and the portions of an executive’s compensation that could vary materially from year to year are primarily performance-based. As a result, high levels of executive compensation in a particular year historically have resulted from excellent Company performance, which the Committee believed did not warrant a reduction in future compensation levels or in our compensation principles. There also is no established policy or target for the allocation between either cash and non-cash or annual and long-term compensation. Rather, the Committee reviews market pay information from Towers Perrin to determine the appropriate level and mix of incentive compensation.

As indicated above, our senior management and, in particular our CEO and COO, played an important part in setting 2007 executive compensation. Besides developing recommendations for the Company performance goals that needed to be met for payouts of 2007 annual incentive awards and long-term incentive awards, they reviewed with the Committee at its November 2006 meeting the performance evaluations of each member of management (other than the CEO), with the CEO giving his performance evaluation of the COO. They also reviewed and discussed with the Committee at its November meeting their recommendations for each member of management (other than the CEO) of 2007 salaries, target annual incentive awards and target long-term incentive awards. As noted above, the CEO’s performance evaluation and the setting of his potential salary, target annual incentive award and target long-term incentive award were conducted by the Committee without any members of management present. The Committee’s performance evaluation of the CEO, along with his 2007 salary, target annual incentive award and target long-term incentive award, were reviewed by the Committee with all independent members of the Board.

The following three sections illustrate the application of our executive compensation principles and discuss in detail the salaries, bonuses and long-term compensation that were approved by the Committee and were paid in connection with 2007 compensation.

Base Salary. As explained above, the base salaries for our executive officers in 2007 were designed to be competitive with the Blended Industry Survey Group for most of our executive officers and with the Energy Services Survey Group for those officers whose responsibilities are limited to utility operations. Base salaries of our executive officers were determined based primarily on an individual’s annual performance evaluation, using as a guideline the salaries at the 50th percentile of the range for executives with similar duties in the appropriate survey group. For 2007, salaries of all officers of OGE Energy were at or below the 50th percentile for executives with similar duties in the Blended Industry Survey Group, while salaries for officers of the utility ranged from approximately 10% below to 10% above the 50th percentile for executives with similar duties in the Energy Services Survey Group. The salaries of executive officers for 2007 were initially determined in November 2006, with an effective date of January 1, 2007. The initial 2007 base salary amounts and percentage increase for the most highly compensated executive officers were as follows: Steven Moore, $807,000, 3%; Peter Delaney, $531,000, 4%; James Hatfield, $375,000, 1%; Danny Harris, $305,000, 9%; Scott Forbes, $223,000, 4% and Paul Renfrow, $219,000, 7%.

Following Mr. Moore’s death in September 2007, Mr. Delaney was appointed as Chairman of the Board and CEO to succeed Mr. Moore. Also, Mr. Danny Harris was appointed Senior Vice President and Chief Operating Officer of the Company. At the Committee’s meeting on October 16, 2007, the Committee increased the annual salaries, effective as of October 1, 2007, of Mr. Delaney from $531,000 to $775,000 and of Mr. Harris from $305,000 to $510,000 in recognition of their increased level of responsibilities. These new salaries were less than the salaries that had been paid to their predecessors in such positions and were based in part on market compensation data provided to the Committee by a compensation consultant. No change was made to any other component of their compensation.

Annual Incentive Compensation. Annual incentive awards with respect to 2007 performance were made under the Annual Incentive Compensation Plan to 106 employees, including all executive officers. The Plan provides executive officers with annual incentive awards, the payment of which is dependent entirely on the achievement of the Company performance goals that, for 2007, were established by the Committee in February 2007.

The amount of the award for each executive officer was expressed as a percentage of base salary as of the end of the first pay period in 2007 (the “targeted amount”), with the officer having the ability, depending upon achievement of the Company performance goals, to receive from 0% to 150% of such targeted amount. For 2007, the targeted amount for Mr. Moore was 100% and ranged from 30% to 70% of base salary for the other executive officers and generally were at or below the 50th percentile of the level of such awards granted to comparable executives in the Blended Industry Survey Group or, in the case of executive officers whose responsibilities are limited to utility operations, to comparable executives in the Energy Services Survey Group. For the most highly compensated executives reported in the Summary Compensation Table on page 26, the targeted amounts were as follows: Mr. Moore, 100% of his 2007 salary; Mr. Delaney, 70% of his 2007 salary; Mr. Hatfield, 55% of his 2007 salary; Mr. Harris, 50% of his 2007 salary; Mr. Forbes, 35% of his 2007 salary and Mr. Renfrow, 35% of his 2007 salary.

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

For each Company performance goal, the Committee established a minimum level of performance (below which no payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made). The following table shows the target levels of performance for the three Company performance goals set for executive officers in 2007, the actual level of performance, as calculated pursuant to the terms of the awards, and the percentage payout of the targeted amount based on the actual level of performance:

Target

Actual
Performance

%
Payout

Earnings Target (1)

$2.40/share

$2.67/share

150%

O&M/

$309 million/

$295.8 million/

115%

Capital Target (1)

$340 - 350 million

$329 million

Unregulated Income Target

$68.0 million

$86.7 million

150.00%

(1) Except as explained below, calculation of the Earnings Target, O&M/Capital Target and Unregulated Income Target were derived from the amounts reported in the Company’s financial statements, with the Earnings Target being the Company’s reported consolidated diluted earnings per share from continuing operations, the Unregulated Income Target being the reported consolidated net income of Enogex from continuing operations, and the O&M/Capital Target being the operating and maintenance expenditures and capital expenditures of various OGE Energy and OG&E business units. At the time of setting these Company performance goals, the Committee specifically excluded various items in calculating the achievement of these performance goals, including, for example, increases or decreases in revenues or expenses from any change in accounting principles occurring during 2007, any gains or losses from the sale, other disposition or impairment of any business or asset during 2007 and operating and maintenance expenses and capital expenditures aggregating in excess of $5.0 million that were incurred to restore electric service following a storm. While the overall effect of these exclusions was to increase the consolidated earnings per share from continuing operations to $2.67 from the reported $2.64 and Enogex’s consolidated net income from continuing operations to $86.7 million from the reported $86.2 million, the exclusions had no effect on the payout to executive officers related to the Earnings Target or the Unregulated Income Target because, even absent the exclusions, the payouts were at the 150% maximum. As to the exclusion for storm-related costs in excess of $5.0 million in calculating the performance of the O&M/Capital Target, this exclusion did affect the payout associated with the O&M/Capital Target as OG&E incurred more than $75.0 million of storm-related costs in 2007, with the vast amount pertaining to the severe ice storm in late 2007 that affected more than 300,000 of the Company’s customers. The Company believes that this exclusion, which was set by the Committee at the same time the 2007 Company performance goals were set in February 2007, is appropriate as it is consistent with the regulatory treatment of OG&E’s storm costs by the Oklahoma Corporation Commission. OG&E is permitted to treat as a regulatory asset for future recovery in electric rates, and to not expense immediately, storm operating and maintenance expenses in excess of $3.5 million per year and to seek recovery in future rate cases of any associated capital expenditures.

The percentage of the targeted amount that an executive officer ultimately received based on corporate performance was subject to being decreased, but not increased, at the discretion of the Committee. For 2007, and as shown by the chart on the preceding page, corporate performance of the Earnings Target, the O&M/Capital Target and the Unregulated Income Target exceeded the target levels of achievement established by the Committee and, based on the level of achievement, the Committee approved payouts under the Annual Incentive Compensation Plan to executive officers ranging from approximately 34% to 103% of their base salaries and from approximately 132.5% to 150% of their targeted amounts. Payouts under the Annual Incentive Compensation Plan are in cash and the amounts paid to the Company’s most highly compensated executive officers are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 26.

Long-Term Incentive Compensation. Long-term incentive awards also were made in 2007 under our Company’s Stock Incentive Plan. The Plan provides for the grant of any or all of the following types of awards: stock options, stock appreciation rights, restricted stock and performance units. In 2007, the Committee set a targeted amount of long-term incentive compensation to be awarded each executive officer, which amount was expressed as a percentage of the individual’s base salary as of January 1, 2007. For 2007, the targeted amount was 175% for Mr. Moore and ranged from 35% to 140% of base salary for the other executive officers. The Company believes that the value of these long-term incentive awards was below the 50th percentile of the level of such awards granted to comparable executives in the Blended Industry Survey Group or, in the case of executive officers whose responsibilities are limited to utility operations, to comparable executives in the Energy Services Survey Group. The targeted amount (expressed as a percentage of salary) of long-term incentive compensation for several executive officers of the Company was more than 10% below the level of such awards granted to comparable executives in the appropriate survey group. This action by the Committee was due to long-term compensation for comparable executives in the appropriate survey group being substantially higher than the amounts awarded by the Committee in the past to such executives of the Company and the Committee’s desire to make up such shortfall over a period of several years rather than through a substantial increase in a particular year. For the most highly compensated executives reported in the Summary Compensation Table on page 26, the targeted amounts of long-term incentive compensation were as follows: Mr. Moore, 175% of his 2007 salary; Mr. Delaney, 140% of his 2007 salary; Mr. Hatfield, 100% of his 2007 salary; Mr. Harris, 75% of his 2007 salary; Mr. Forbes, 50% of his 2007 salary and Mr. Renfrow, 50% of his 2007 salary.

Historically, the Committee had awarded long-term compensation in the forms of stock options and restricted stock. At its meeting in the fourth quarter of 2002, the Committee chose to discontinue awarding restricted stock and, instead, to make awards of stock options and performance units commencing in 2003, with 50% of an executive officer’s award being in the form of stock options and 50% in the form of performance units. For 2004,

the Committee chose to place less emphasis on stock options with 25% of an executive officer’s award of long-term compensation being in the form of stock options and 75% in the form of performance units. In 2005, the Committee decided to cease awarding stock options and instead, since 2005, has awarded all long-term compensation in the form of performance units with, as explained below, payout of the performance units being dependent on achievement of Company performance goals set by the Committee. Specifically, for 75% of the performance units awarded in 2007, the Company performance goal is based on the relative total shareholder return (“TSR”) of the Company’s Common Stock over the three-year period ending December 31, 2009 compared to a peer group and, for the remaining 25%, the Company performance goal is based on the growth in the Company’s earnings per share over the same three-year period compared to an earnings growth target (the “Earnings Growth Target”) set by the Committee.

The performance units were granted to executive officers on March 14, 2007, immediately following the Committee’s meeting on such date. The number of performance units granted was determined by taking the amount of the executive’s long-term compensation to be delivered in performance units (expressed as a percentage of the executive’s 2007 base salary and as determined above) and dividing that amount by $37.11, which was the closing price of a share of the Company’s Common Stock on March 13, 2007. This resulted in executives receiving a number of performance units with a value at the date of grant from 35% to 175% of their 2007 base salaries. All payouts of such performance units will be made in shares of the Company’s Common Stock, which causes the value of the performance units to be substantially dependent upon the changing value of the Company’s Common Stock in the marketplace. As indicated above, the terms of 75% of the performance units granted to each executive officer in 2007 entitle the officer to receive from 0% to 200% of the performance units granted depending upon the Company’s TSR over a three-year period (defined as share price increase (decrease) since December 31, 2006 plus dividends paid, divided by share price at December 31, 2006) measured against the TSR for such period of a peer group selected by the Committee. The peer group for measuring the Company’s TSR performance consists of approximately 80 utility holding companies and gas and electric utilities in the Standard & Poor’s Utility Index. At the end of the three-year period (i.e., December 31, 2009), the terms of these performance units provide for payout of 100% of the performance units initially granted if the Company’s TSR is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if the Company’s TSR is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Company’s TSR is below the 50th percentile of the peer group, with no payout for performance below the 35th percentile.

For the remaining 25% of performance units granted to each executive officer in 2007, the officer is entitled to receive from 0% to 200% of the performance units granted depending upon the growth in the Company’s earnings per share (“EPS”) over the three-year period ending December 31, 2009. The growth in the earnings per share will be measured from $2.45 per share (which consisted of the $2.45 earned in 2006 from continuing operations), against the Earnings Growth Target (4.00% per year) set by the Committee for such period. At the end of the three-year period (i.e., December 31, 2009), the terms of these performance units provide for payout of 100% of the performance units initially granted if the rate of growth of the Company’s earnings per share during such period is at the Earnings Growth Target, with higher payouts for growth rates in excess of the Earnings Growth Target up to 200% for growth rates at or above 150% of the Earnings Growth Target and payout of less than 100% for growth rates below the Earnings Growth Target, with no payouts for growth rates below 62.5% of the Earnings Growth Target. The Company’s earnings growth rate is calculated on a point-to-point basis by dividing by one-third the percentage increase in the Company’s earnings per share for the year ended December 31, 2009, compared to the benchmark of $2.45 for 2006.

In January 2005, as part of their long-term compensation, executive officers received performance units for which the payout of 75% of the performance units was dependent on the achievement of a Company performance goal based on TSR for the three-year period ended December 31, 2007 and 25% was dependent on the growth of the Company’s earnings per share of $1.73 for the year ended December 31, 2004 compared to the Earnings Growth Target for the three-year period ended December 31, 2007. The Company’s TSR for such period was at approximately the 62nd percentile (approximately the top 38%) of the peer group. Stated differently, the percentage return on the Company’s Common Stock, consisting of increases (decreases) in the price of the Company’s Common Stock plus dividends paid, was higher than 62% of the companies in the Standard & Poor’s Utility Index during the period commencing on January 1, 2005 and ending on December 31, 2007. The Company’s earnings per share growth (calculated on a point-to-point basis by dividing by one third the percentage increase in the Company’s earnings per share for the year ended December 31, 2007 of $2.64, compared to the benchmark of $1.73 for the year ended December 31, 2004) was 17.53%. This high level of performance resulted in payouts in February 2008 of approximately 130% of the 2005 performance units that were based on TSR, 200% of the

performance units based on earnings per share growth and an overall payout of 147% of the performance units originally awarded in 2005. The value of these payouts is reflected in the Stock Awards – Value Realized on Vesting column of the Option Exercises and Stock Vested Table on page 29.

CEO Compensation. The 2007 compensation for Mr. Moore consisted of the same components as the compensation for other executive officers and was based on the same compensation principles and policies as was used in setting compensation for other executive officers. For 2007, Mr. Moore’s salary was increased from $780,000 to $807,000, and his 2007 targeted award under the Annual Incentive Plan was increased from 85% to 100% of his base salary, which the Committee believed were appropriate levels based on his performance and the amounts paid to a chief executive officer in the Blended Industry Survey Group. With Mr. Moore’s death in September 2007 and in accordance with the terms of the Annual Incentive Plan, Mr. Moore’s beneficiary was entitled to a prorated payout (based on Mr. Moore’s number of months of employment in 2007 prior to his death) of his award for 2007 under the Plan to the extent the Company performance goals applicable to his award were met. As a result of the actual level of performance of the 2007 Company performance goals described above, Mr. Moore’s beneficiary was entitled to a prorated payout of $833,029 under the Annual Incentive Plan, representing approximately 103% of his base salary and 103% of his targeted award. Mr. Moore also received as long-term compensation in March 2007 an award of 38,056 performance units, having an estimated value of 175% of his 2007 base salary. The terms of these performance units are identical to those awarded other executives and are described above, except that, due to Mr. Moore’s death, any payout of these performance units following the end of the three-year performance period ending December 31, 2009, will be prorated based on Mr. Moore’s months of employment prior to his death during such three-year performance period. The award of performance units in 2007 made to Mr. Moore was based on his prior performance and a comparison of his award to the long-term compensation of other chief executive officers in the 50th percentile of the Energy Services Survey Group and of the Blended Industry Survey Group. Consideration also was given by the Committee to Mr. Moore’s prior experience with the Company and OG&E, his demonstrated leadership skills and his positive reputation within the community and utility industry.

Following his death in September 2007, Mr. Moore’s beneficiary was entitled to receive a prorated payout of approximately 131% of the earned performance units granted to Mr. Moore in January 2005 based on (i) the Company’s TSR for the three years ended December 31, 2007 being at approximately the 62nd percentile (approximately the top 38%) of the peer group selected by the Committee, (ii) the average annual growth in the Company’s EPS for the three years ended December 31, 2007 being 17.53% and (iii) Mr. Moore having been employed by the Company prior to his death for approximately 32 of the 36 months ending December 31, 2007. This resulted in a payout of 61,938 units, of which two-thirds (41,291) were paid in shares of the Company’s Common Stock and one-third (20,647) was paid in cash based on the closing price of the Company’s Common Stock on December 31, 2007. The value of this payout, based on the closing price of the Company’s Common Stock on December 31, 2007, is reported in the Stock Awards – Value Realized on Vesting column of the Option Exercises and Stock Vested Table on page 29. Mr. Moore’s beneficiary also received a payout in accordance with the terms of the Company’s non-qualified deferred compensation plan, proceeds from life insurance policies and a distribution from the retirement plan, in each case as described in more detail under “Nonqualified Deferred Compensation” and “Pension Benefits” below.

The 2007 compensation for Mr. Delaney consisted of the same components as the compensation for other executive officers and was based on the same compensation principles and policies as was used in setting compensation for other executive officers. For 2007, Mr. Delaney’s salary initially was increased from $510,000 to $531,000, and his 2007 targeted award under the Annual Incentive Plan remained unchanged at 70% of his base salary, which the Committee believed were appropriate levels based on his performance and the amounts paid to a chief operating officer in the Blended Industry Survey Group. Mr. Delaney also received as long-term compensation in March 2007 an award of 20,032 performance units, having an estimated value of 140% of his 2007 base salary. The terms of these performance units are identical to those awarded other executives and are described above. The award of performance units in 2007 made to Mr. Delaney was based on his performance and a comparison of his award to the long-term compensation of other chief operating officers in the 50th percentile of the Energy Services Survey Group and of the Blended Industry Survey Group. As described above, effective as of October 1, 2007, in recognition of the increased level of responsibilities in connection with his appointment as Chairman and Chief Executive Officer, Mr. Delaney’s annual salary was increased from $531,000 to $775,000. No change was made to any other component of his compensation.

As a result of 2007 corporate performance of the corporate goals described above, Mr. Delaney was entitled to a payout of $525,026 under the Annual Incentive Plan, representing approximately 99% of his initial base salary

and 141.25% of his targeted award. Like other executive officers, Mr. Delaney also received in February 2008 a payout of 147% of the performance units granted to Mr. Delaney in January 2005 based on the Company’s TSR for the three years ended December 31, 2007 being at the approximately the 62nd percentile (approximately the top 38%) of the peer group selected by the Committee and the average annual growth of the Company’s EPS for the three years ended December 31, 2007 being 17.53%. This resulted in Mr. Delaney receiving a payout of 39,717 units, of which two-thirds (26,477) were paid in shares of the Company’s Common Stock and one-third (13,240) was paid in cash based on the closing price of the Company’s Common Stock on December 31, 2007. The value of this payout, based on the closing price of the Company’s Common Stock on December 31, 2007, is reported in the Stock Awards – Value Realized on Vesting column of the Option Exercises and Stock Vested Table on page 29.

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

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

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

The Company also offers executive officers a limited amount of perquisites. These include up to $7,500 annually for tax and financial planning services, payment of dues at luncheon and country clubs, an annual physical exam and, in the case of Mr. Moore, a leased car. The perquisite for tax and financial planning services was discontinued by the Committee during 2007. The value of the perquisites received by each executive officer, other than Mr. Moore, was less than $10,000 in 2007. In reviewing the perquisites and benefits under the SERP, Retirement Savings Plan, deferred compensation plan, pension plan and related restoration plan, the Committee sought in 2007 to provide participants with benefits at least commensurate with those offered by other utilities of comparable size.

Change-of-Control Provisions. Each of the executive officers has an employment agreement that provides for specified benefits upon termination following a change of control. As explained in detail below under the heading “Potential Payments Upon Termination or Change of Control,” if an executive officer’s employment is terminated by the Company without “cause” or by the executive for “good reason” (as defined) following a change of control, the executive officer is entitled to, among other things, a severance payment equal to 2.99 times the sum of such officer’s (a) annual base salary and (b) highest recent annual bonus. “Good reason” is defined to include the ability of the executive to terminate voluntarily for any reason during the 30-day period immediately following the one-year anniversary of the change of control. This type of provision is sometimes called a modified “double-trigger” because payment is made only if there is a change of control and the executive officer’s employment is terminated. The agreements utilize a modified double-trigger because the Board of Directors believes change-of-control payments only should be made if there is a separation of employment following a change-of-control, but also believes that

the right to voluntarily terminate for any reason within 30 days after the first anniversary of the change of control helps to ensure that the executive’s services will be available during an important transition period. The 2.99 times multiple for change-of-control payments was selected because at the time it was considered standard. Although many companies also include provisions for tax gross-up payments to cover any excise taxes on excess parachute payments, the Board of Directors of the Company decided not to include this additional benefit in the Company’s agreements. Instead, as explained on page 33 below, under the Company’s agreements if the excise tax would be imposed, the change-of-control payments will be reduced to a point where no excise tax would be payable, if such reduction would result in a greater after-tax payment. For more information regarding the employment agreements, please see “Potential Payments Upon Termination or Change of Control” below.

In addition, pursuant to the terms of the Company’s incentive compensation plans, upon a change of control, all stock options will vest immediately and, for a 60-day period following the change of control, executive officers may surrender their options and receive in return a cash payment equal to the excess of the change of control price (as defined) over the exercise price; all performance units will vest and be paid out immediately in cash as if the applicable performance goals had been satisfied at target levels; and any annual incentive award outstanding for the year in which the participant’s termination occurs for any reason, other than cause, within 24 months after the change of control will be paid in cash at target level on a prorated basis.

Stock Ownership Guidelines. In an effort to further align management’s interests with those of the share-owners, the Committee recommended, and the Board of Directors adopted, stock ownership guidelines for the officers of the Company and its subsidiaries during 2004. The Committee reviewed and revised the guidelines in 2008, with the primary change being to increase the stock ownership guidelines for several officers. 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 CEO is five times base salary. The guidelines for other Company officers range from three and one-half to (with one exception) two times their base salaries. Each executive is expected to achieve the applicable ownership guideline within approximately five years of his or her most recent promotion. Similar guidelines are in place for members of the Board of Directors at a level of five times their annual retainer.

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

Tax and Accounting Issues.

Deductibility of Executive Compensation. A Federal tax law currently limits our ability to deduct certain 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 steps to ensure the continued deductibility of its executive compensation where appropriate. 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. The 2008 Stock Incentive Plan and the 2008 Annual Incentive Compensation Plan also are being submitted to the shareowners at this Annual Meeting for the same reason.

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

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

SUMMARY COMPENSATION TABLE

The following table provides information regarding compensation paid or to be paid by us or any of our subsidiaries to each person who served as Chief Executive Officer during 2007, the Chief Financial Officer and the three other most highly compensated executive officers at December 31, 2007.

Name and

Principal Position

Year

Salary
($)

Bonus
($)

Stock Awards
($) (1)

Option Awards
($) (2)

Non-Equity Incentive Plan Compensation
($) (3)

Change in Pension Value and Nonquali-
fied Deferred Compensation Earnings
($) (4)

All Other Compensation ($) (5)

Total

($)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

P.B. Delaney, President and
Chief Executive
Officer (6)

2007

2006

$591,063

$510,000

$720,490

$1,366,449

$10,022

$525,026

$491,714

$272,054

$582,898

$52,142

$68,274

$2,160,775

$3,029,357

J.R. Hatfield,
Sr. Vice President
and Chief Financial
Officer

2007

2006

$375,000

$370,700

$342,687

$646,150

$4,806

$287,719

$275,820

$357,228

$61,694

$33,088

$39,078

$1,395,722

$1,398,248

D.P. Harris,
Sr. Vice President
and Chief
Operating Officer,
OGE Energy and
President,
Enogex Inc.

2007

2006

$355,463

$284,000

$165,812

$262,992

$1,549

$228,750

$170,400

$551,462

$55,659

$27,728

$22,752

$1,329,215

$797,352

H.S. Forbes, Controller and
Chief Accounting
Officer

2007

2006

$223,000

$214,000

$55,676

$50,748

$108,880

$101,326

$15,914

$11,102

$21,530

$15,196

$425,000

$392,372

P.L. Renfrow

Vice President,
Public Affairs

2007

2006

$219,000

$205,000

$6,000

$76,950

$125,338

$797

$106,927

$97,065

$264,323

$42,749

$17,839

$15,722

$685,039

$492,671

S.E. Moore,
Former Chairman
and Chief Execu-
tive Officer (7)

2007

2006

$589,755

$780,000

$124,344

$2,538,567

$19,384

$833,029

$913,183

$3,024,534

$410,186

$2,966,059

$111,290

$4,684,150

$4,772,610

(1)	Amounts in this column reflect the dollar amount recognized for financial statement reporting purposes for the particular year in accordance with SFAS No. 123R, “Share-Based Payment” (“FAS 123R”), for the performance units during the three-year period ending December 31 of the year being reported. All performance units are subject to a three-year performance period. The assumptions used in the valuation are discussed in Note 4 to our Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2007.
(2)	Amounts in this column reflect the dollar amount recognized for financial statement reporting purposes for the particular year in accordance with FAS 123R, for stock options awarded in 2004. There were no stock options granted in subsequent years. The assumptions used in this valuation are discussed in Note 4 to our Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2007.
(3)	Amounts in this column reflect payments under our Annual Incentive Compensation Plan.
(4)	Amounts in this column reflect the actuarial increase in the present value of the named executive officer’s benefits under all pension plans established by the Company determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and includes amounts which the named executive officer may not currently be entitled to receive because such amounts are not vested.
(5)	Amounts in this column for 2007 reflect: (i) for Mr. Delaney, $34,813 (Retirement Savings Plan and Deferred Compensation Plan) and $9,736 (insurance premiums); (ii) for Mr. Hatfield, $19,525 (Retirement Savings Plan and Deferred Compensation Plan) and $5,198 (insurance premiums); (iii) for Mr. Harris, $15,663 (Retirement Savings Plan and Deferred Compensation Plan) and $11,465 (insurance premiums); (iv) for Mr. Forbes, $19,460 (Retirement Savings Plan and Deferred Compensation Plan) and $2,070 (insurance premiums); (v) for Mr. Renfrow, $9,482 (Retirement Savings Plan and Deferred Compensation Plan) and $2,004 (insurance premiums); and (vi) for Mr. Moore, $68,330 (Retirement Savings Plan Deferred Compensation Plan) $20,936 (insurance premiums) and $2,853,571 as proceeds from life insurance policies payable to his beneficiary upon his death and for which the premiums had previously been reported. 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. In addition, amounts in the column include for Mr. Moore $23,222 of perquisites, consisting of $9,823 for a Company car and $13,399 for payment of dues at luncheon and country clubs. The value of the perquisites for the other named executive officers also is included, but, in each instance, the amount was less than $10,000 in 2007.

(6)	Mr. Delaney was elected Chief Executive Officer on September 22, 2007. Prior thereto, he served as President and Chief Operating Officer.
(7)	Mr. Moore served as Chairman and Chief Executive Officer until his death in September 2007.

Grants of Plan-Based Awards Table

Name

Grant Date

Estimated Future Payouts Under Non-
Equity Incentive Plan Awards

Estimated Future Payouts Under Equity Incentive Plan Awards

All Other
Stock Awards:
Number of
Shares of Stock
or Units

(#)

All Other

Option Awards:
Number of
Securities
Underlying
Options
(#)

Exercise
or Base
Price of
Option
Awards
($/Sh)

Grant Date
Fair Value
of Stock
and Option
Awards
($)(1)

Threshold
($)

Target
($)

Maximum
($)

Threshold
(#)

Target
(#)

Maximum
(#)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

P.B. Delaney

2/28/2007

3/14/2007

$371,700

$557,550

20,032

40,064

N/A

$531,499

J.R. Hatfield

2/28/2007

3/14/2007

$206,250

$309,375

10,105

20,210

N/A

$268,109

D.P. Harris

2/28/2007

3/14/2007

$152,500

$228,750

6,164

12,328

N/A

$163,546

H.S. Forbes

2/28/2007

3/14/2007

$78,050

$117,075

3,004

6,008

N/A

$79,704

P.L. Renfrow

2/28/2007

3/14/2007

$76,650

$114,975

2,951

5,902

N/A

$78,300

S.E. Moore

2/28/07

3/14/07

$589,755

$884,632

8,457(2)

16,914(2)

N/A

$224,383

(1)

The grant date fair value is calculated in accordance with FAS 123R.

(2)

Represents prorated amount based on Mr. Moore’s number of months of employment prior to his death during the three-year performance period.

Amounts in columns (c), (d) and (e) of the Grants of Plan-Based Awards table above represent the minimum, target and maximum amounts that would be payable pursuant to the 2007 annual incentive awards made under the Annual Incentive Compensation Plan. As described in the Compensation Discussion and Analysis section above, the amount that each executive officer received was dependent upon performance against two or more of the following performance measures: Earnings Target, O&M/Capital Target and Unregulated Income Target. For each Company performance measure, the Compensation Committee established a minimum level of performance (below which no payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made). The percentage of the targeted amount that an executive officer ultimately received based on corporate performance was subject to being decreased, but not increased, at the discretion of the Committee. For 2007, payouts of these annual incentive awards were made in cash and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Amounts in columns (f), (g) and (h) above represent awards of performance units under the Company’s Stock Incentive Plan. All payouts of such performance units will be made in shares of the Company’s Common Stock. As described in more detail in the Compensation Discussion and Analysis section above, the terms of 75% of the performance units granted to each executive officer in 2007 entitle the officer to receive from 0% to 200% of the performance units granted depending upon the Company’s TSR over a three-year period measured against the TSR for such period by a peer group selected by the Committee. At the end of the three-year period (i.e., December 31, 2009), the terms of these performance units provide for payout of 100% of the performance units initially granted if the Company’s TSR is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if the Company’s TSR is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Company’s TSR is below the 50th percentile of the peer group, with no payout for performance below the 35th percentile.

For the remaining 25% of performance units granted in of 2007, the officer is entitled to receive from 0% to 200% the performance units granted based on the growth in the Company’s earnings per share measured against the

Earnings Growth Target set by the Committee for such period. At the end of the three-year period (i.e., December 31, 2009), the terms of these performance units provide for payout of 100% of the performance units initially granted if the rate of growth of the Company’s earnings per share during such period is at the Earnings Growth Target, with higher payouts for growth rates in excess of the Earnings Growth Target up to 200% for growth rates at or above 150% of the Earnings Growth Target and payout of less than 100% for growth rates below the Earnings Growth Target, with no payouts for growth rates below 62.5% of the Earnings Growth Target. The Company’s earnings growth rate is calculated on a point-to-point basis by dividing by one-third the percentage increase in the Company’s earnings per share for the year ended December 31, 2009, compared to the benchmark of $2.45 for 2006.

Based on the grant date fair value of equity awards granted to the named executive officers in 2007 and the base salary of the named executive officers, “Salary” accounted for approximately 40% to 59% of total compensation, while incentive compensation accounted for approximately 41% to 60% of the total compensation, assuming achievement of a target level of performance for each named executive officer. Because the value of certain equity awards included in the Summary Compensation Table is based on compensation expense in accordance with FAS 123R rather than grant date fair value, these percentages may not be able to be derived using the amounts reflected in the Summary Compensation Table.

Outstanding Equity Awards at Fiscal Year-End Table

Option Awards

Stock Awards

Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexerciseable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (1)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(2)

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
P.B. Delaney	44,000 43,200 77,400	0 0 0	0 0 0	23.575 16.685 22.700	1/21/2014 1/27/2013 3/15/2012	N/A	N/A	40,064(3) 62,024(4)	$1,453,923 $2,250,051
J.R. Hatfield	14,067 1	0 0	0 0	23.575 16.685	1/21/2014 1/27/2013	N/A	N/A	20,210(3) 31,934(4)	$733,421 $1,158,885
D.P. Harris	6,800 10,934 5,567	0 0 0	0 0 0	23.575 16.685 22.230	1/21/2014 1/27/2013 1/16/2012	N/A	N/A	12,328(3) 15,830(4)	$447,383 $574,471
H.S. Forbes	0	0	0	N/A	N/A	N/A	N/A	6,008(3) 9,760(4)	$218,030 $354,190
P.L. Renfrow	0	0	0	N/A	N/A	N/A	N/A	5,902(3) 7,272(4)	$214,184 $263,901
S.E. Moore	85,100 202,300 218,500 104,700 77,800 72,800	0 0 0 0 0 0	0 0 0 0 0 0	23.575 16.685 22.230 22.500 18.250 28.750	9/21/2010 9/21/2008 9/21/2008 9/21/2008 9/21/2008 9/21/2008	N/A	N/A	16,914(3) 65,876(4)	$613,809 $2,390,640

(1)	The number of units is based on achieving maximum performance resulting in payout of 200% of target.

(2)	Values were calculated based on a $36.29 closing price of OGE Energy Common Stock, as reported on the New York Stock Exchange at December 31, 2007.

(3)	These amounts represent performance units for the performance period January 1, 2007 to December 31, 2009.

(4)	These amounts represent performance units for the performance period January 1, 2006 to December 31, 2008.

Option Exercises and Stock Vested Table

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#) (1)	Value Realized on Vesting ($)
(a)	(b)	(c)	(d)	(e)
P.B. Delaney	7,500	$109,343	39,717	$1,372,490
J.R. Hatfield	N/A	N/A	17,560	$606,817
D.P. Harris	N/A	N/A	7,496	$259,038
H.S. Forbes	N/A	N/A	N/A	N/A
P.L. Renfrow	1,167	$14,735	3,488	$120,535
S.E. Moore	104,000	$1,307,405	61,938	$2,140,373

(1)

Reflects value of payout of performance units awarded in January 2005, 75% of whose payout was dependent on the achievement of a Company performance goal based on TSR for the three-year period ended December 31, 2007 and 25% was dependent on the achievement of a Company performance goal based on annual growth in Earnings Per Share over the same period. The Company’s TSR for such period was at approximately the 62nd percentile (approximately the top 38%) of the peer group and the Company’s annual average EPS growth for such period was 17.53%, which resulted in overall payouts in February 2008 of 147% of the performance units originally awarded in January 2005. Awards were paid out two-thirds in shares of the Company’s common stock and one-third in cash.

Pension Benefits Table

Name

Plan Name

Number of Years Credited Service

(#)(1)

Present

Value of Accumulated Benefit

($)(2)

Payments

During Last

Fiscal Year

($)

(a)

(b)

(c)

(d)

(e)

P.B. Delaney

Qualified Plan

Restoration Plan

SERP

5.75

8.75

$66,693

$156,136

$3,472,857

J.R. Hatfield

Qualified Plan

Restoration Plan

13.33

$305,858

$542,723

D.P. Harris

Qualified Plan

Restoration Plan

11.67

$262,622

$616,632

H.S. Forbes

Qualified Plan

Restoration Plan

2.33

$24,753

$6,118

P.L. Renfrow

Qualified Plan

Restoration Plan

15.75

$411,338

$147,405

S.E. Moore

Qualified Plan

Restoration Plan

33.17

$1,288,625

$7,958,484

$1,288,625

$7,958,484

(1)

Generally, a participant’s years of credited service are based on his or her years of employment with the Company. However, in connection with Mr. Delaney’s hiring in 2002, he was awarded three additional years of credited service under the SERP. These additional years of service accelerate the early retirement eligibility and vesting of Mr. Delaney’s SERP benefit by three years from age 58 to age 55 but have no impact in determining the present value of his accumulated SERP benefit payable at his normal retirement age.

(2)

Amounts in this column reflect the present value of the named executive officer’s benefits under all pension plans established by the Company determined using interest rate and mortality rate assumptions consistent with those used in Note 14 to our Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2007, and includes amounts which the named executive officer may not currently be entitled to receive because such amounts are not vested.

The Company and its subsidiaries maintain a qualified non-contributory pension plan (the “Retirement Plan”) generally covering all employees who have completed one year of service. Subject to limitations imposed by the Code, benefits payable under the Retirement Plan to employees hired prior to February 1, 2000 are based upon (i) the average of the five highest consecutive years of compensation (which for the executives named in the Summary Compensation Table consists of salary and annual bonus or incentive compensation) during an employee’s last ten years prior to retirement and (ii) length of service. Social Security benefits are deducted in determining benefits payable under the Retirement Plan. Compensation covered by the Retirement Plan includes salaries, annual bonuses or incentive compensation and overtime pay. Benefits are reduced for each year prior to age 62 that an employee retires. For an employee retiring prior to age 62, there is an alternative method of computing the reduction in benefits that is based on years of service and age, with an employee whose age and years of service total or exceed 80 at the time of retirement receiving no reduction in the benefits payable under the plan. An employee may elect at the time of retirement to receive, in lieu of an annuity, a lump-sum payment equal to the present value of the annuity. For employees hired after January 31, 2000, however, the Retirement Plan is a cash balance plan, under which the Company annually will contribute to the employee’s account an amount equal to 5% of the employee’s annual compensation plus accrued interest. Employees hired prior to February 1, 2000 receive the greater of the cash balance formula or final average compensation formula described above. Retirement benefits are payable to participants upon normal retirement (at or after age 65) or early retirement (at or after attaining age 55 and completing five or more years of service), to former employees after reaching retirement age (or, if elected, following termination) who have completed five or more years of service before terminating their employment and to participants after reaching retirement age (or, if elected, following termination) upon total and permanent disability. As indicated above, the benefits payable under the Retirement Plan are subject to maximum limitations under the Code. Should benefits for a participant at the time of retirement exceed the then permissible limits of the Code, the Retirement Restoration Plan will provide benefits through a lump-sum distribution following retirement as provided in the Retirement Restoration Plan, which benefits shall be actuarially equivalent to the amounts that would have been, but cannot be, payable to such participant annually under the Retirement Plan because of the Code limits. The Company and its subsidiaries fund the estimated benefits payable under the Retirement Restoration Plan through contributions to a grantor trust for the benefit of those employees who will be entitled to receive payments under the Retirement Restoration Plan. Of the named executive officers, Mr. Moore was eligible for early retirement. As a result of his death in September 2007, Mr. Moore’s beneficiary received under the retirement plan and the retirement restoration plan the payment shown in the chart on the preceding page following his death.

In 1993, OG&E adopted a SERP which is an unfunded supplemental executive retirement plan that is not subject to the benefit limits imposed by the Code. The plan generally provides for an annual retirement benefit at age 65 equal to 65% of the participant’s average compensation during his or her final 36 months of employment, reduced by Social Security benefits, by amounts payable under the Retirement and Restoration Retirement Plans described above and by amounts received under pension plans from other employers. For a participant in the SERP who retires before age 65, the 65% benefit is reduced, with the reduction being 1% per year for ages 62 through 64, an additional 2% per year for ages 60 through 61, an additional 4% per year for ages 58 through 59 and an additional 6% per year for ages 55 through 57, so that a participant retiring at age 55 would receive 32% of his average compensation during his final 36 months, reduced by the deductions set forth above. Payment will be made in a lump sum following termination as provided in the SERP in an amount equal to the actuarial equivalent of the applicable annuity. Other than Mr. Delaney, no employee participated in the SERP during 2007.

Nonqualified Deferred Compensation Table

Name	Executive Contributions in Last FY ($)(1)	Registrant Contributions in Last FY ($)(1)	Aggregate Earnings in Last FY ($)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at Last FYE ($)
(a)	(b)	(c)	(d)	(e)	(f)
P.B. Delaney	$245,857	$21,313	$46,590	0	$1,426,385
J.R. Hatfield	$30,057	$12,775	$3,615	0	$281,474
D.P. Harris	$177,731	$9,711	$29,244	0	$601,034
H.S. Forbes	$111,500	$6,690	$2,169	0	$120,359
P.L. Renfrow	$9,785	$3,615	$827	0	$22,744
S.E. Moore	$895,547	$58,205	$320,546	$13,466,060	0

(1)

All executive and registrant contributions in the last fiscal year are reported as compensation to such executive officer in the Summary Compensation Table on page 26. The specific aggregate amounts reported for each of such officers is: P.B. Delaney, $267,170; J.R. Hatfield, $42,832; D.P. Harris, $187,442; H.S. Forbes, $118,190; P.L. Renfrow, $13,400; and S.E. Moore $953,752.


(2)	Reflects the following amounts for each of the following executive officers that were reported as compensation to such executive officer in last year’s Summary Compensation Table: P.B. Delaney, $354,864; J.R. Hatfield, $30,994; and D.P. Harris, $97,953.

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

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

Deferrals, plus any Company match, are credited to a special recordkeeping account in the participant’s name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. For 2007, those investment fund options (and investment returns) included an OGE Energy Common Stock fund (5.98 percent); 500 Index B (MFC Global Investment) (5.25 percent); Active Bond (John Hancock Advisers, Inc.) (4.03 percent); Blue Chip Growth (T. Rowe Price) (12.81 percent); Capital Appreciation (Jennison Associates LLC) (11.70 percent); Equity-Income (T. Rowe Price) (3.39 percent); Growth & Income (Grantham, Mayo, Van Otterloo & Co.) (4.07 percent); Managed (GMO/DMR) (1.95 percent); Money Market B (MFC Global Investment) (4.82 percent); Overseas Equity (Capital Guardian Trust Company) (12.53 percent); and Small Cap Growth (Wellington Management) (13.98 percent).

Normally, payments under the deferred compensation plan begin within one year after retirement. For these purposes, normal retirement age is 65 and the minimum age to qualify for early retirement is age 55 with at least five years of service. Benefits will be paid, at the election of the participant, either in a lump sum or a stream of annual payments for up to 15 years, or a combination thereof. Participants whose employment terminates before

they qualify for retirement benefits will receive their vested account balance in one lump sum following termination as provided in the plan. Participants also will be entitled to pre- and post-retirement survivor benefits. If the participant dies while in employment before retirement, his or her beneficiary will receive a payment of the account balance plus a supplemental survivor benefit equal to two times the total amount of base salary and bonuses deferred under the plan. Accordingly, following his death in September 2007, Mr. Moore’s beneficiary received such a distribution from the deferred compensation plan. The amount of the distribution is reflected in the table above. If the participant dies following retirement, his or her beneficiary will continue to receive the remaining vested account balance. Additionally, eligible surviving spouses will be entitled to a lifetime survivor annuity payable annually. The amount of the annuity is based on 50% of the participant’s account balance at retirement, the spouse’s age and actuarial assumptions established by the Company’s benefit committee.

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

COMPENSATION COMMITTEE REPORT

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

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

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

Compensation Committee

Luke R. Corbett, Chairman

Herbert H. Champlin, Member

Kirk Humphreys, Member*

John D. Groendyke, Member

Robert Kelley, Member

Leroy C. Richie, Member*

Ronald H. White, M.D., Member

J. D. Williams, Member

* Mr. Humphreys and Mr. Richie were members only for the February 2008 meeting.

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

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

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

If, during the Employment Period, the employer terminates the officer’s employment for reasons other than cause, death or disability or if the officer terminates his or her employment for good reason, the officer is entitled to the following payments: (i) all accrued and unpaid compensation and a prorated annual bonus and (ii) a severance payment equal to 2.99 times the sum of such officer’s (a) annual base salary and (b) highest recent annual bonus. The officer is entitled to receive such amounts in a lump-sum payment within 30 days of termination, although if the officer is a “specified employee” (within the meaning of Code Section 409A), payment of the prorated bonus and severance payment will be delayed until the first day of the seventh month following the officer’s termination (or earlier death). The officer also is entitled to continued welfare benefits for three years and outplacement services. If these payments and benefits, when taken together with any other payments to the officer, would result in the imposition of the excise tax on excess parachute payments under Section 4999 of the Code, then the severance benefits will be reduced to the extent where no excise tax would be payable if such reduction results in a greater after-tax payment to the officer. For these purposes, good reason means (i) a diminution in the officer’s position, authority, duties or responsibilities, (ii) a failure by the Company to comply with specified provisions of the employment agreement, (iii) the officer is required to be based at a different office or location 50 miles or more away or is required to travel to a substantially greater extent, and (iv) any purported termination by the Company of the officer’s employment other than as expressly permitted by the employment agreement. In addition, a termination by the officer for any reason during the 30-day period following the first anniversary of the change of control will be deemed a termination for good reason.

Assuming that a change of control had occurred and the named executive officers (other than Mr. Moore) were terminated on December 31, 2007 and that the price of OGE Energy’s Common Stock was $36.29 (the closing price on December 31, 2007), then the named executive officers would have been entitled to the following lump sum severance payments under their employment agreements: P.B. Delaney, $2,808,964; J.R. Hatfield, $1,397,070; D.P. Harris, $1,695,300; H.S. Forbes, $768,096 and P.L. Renfrow $751,875. For these purposes, we have assumed that the payments would not result in the imposition of the excise tax on excess parachute payments, which if triggered, could result in a reduction of the foregoing amounts. The named executive officers would also be entitled to outplacement services, valued at approximately $50,000 each, and continued welfare benefits for three years at a value of approximately $31,000 each. For these purposes we have assumed that health care costs will increase at the rate of 9% per year. These officers also would be entitled to the retirement benefits they would otherwise be entitled to receive as set forth in the Pension Benefits table on page 29 and, as described above, Mr. Delaney would be considered vested under the SERP. Finally, matching credits under the nonqualified deferred compensation plan would vest and the officers would be entitled to the benefits set forth in the Nonqualified Deferred Compensation table on page 31.

In addition, pursuant to the terms of the Company’s incentive compensation plans, upon a change of control, all stock options and restricted stock will vest immediately and, for a 60-day period following the change of control, executive officers may surrender their options and receive in return a cash payment equal to the excess of the change

of control price (as defined) over the exercise price; all performance units will vest and be paid out immediately in cash as if the applicable performance goals had been obtained at target levels; and any annual incentive award outstanding for the year in which the participant’s termination occurs for any reason other than cause, within 24 months after the change of control will be paid in cash at target level on a prorated basis. Although all outstanding stock options are already exercisable, upon a change of control, executive officers could surrender their options and receive a cash payment equal to the excess of the change of control price over the exercise price. Assuming that a change of control occurred on December 31, 2007 and that the price of our common stock (and the change of control price) was $36.29 (the closing price on December 31, 2007), then the named executive officers would have been entitled to the following lump sum payments for outstanding stock options and performance unit awards: P.B. Delaney, $4,310,649; J.R. Hatfield, $1,125,035; D.P. Harris, $889,524; H.S. Forbes, $286,110 and P.L. Renfrow $236,042. In addition, each executive officer would have received the same payout of the earned annual incentive compensation for 2007 that is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 26 and the same payout of long-term compensation for the performance units whose three-year performance period ended December 31, 2007 as reflected in the Stock Awards - Value Realized on Vesting column in the Option Exercises and Stock Vested Table on page 29. The reason for the same payouts is that the individual would have been employed throughout the entire performance period for the awards.

If a named executive officer terminates employment other than following a change of control as described above, such officer will be entitled to receive amounts earned during the course of his or her employment, including accrued salary and unpaid salary and unused vacation pay. If the termination was a result of death, disability or retirement, the executive officer or his or her representative could exercise his or her stock options generally for three years (one year in the event of death for shares granted prior to 2004) or their stated term, if less, and would be entitled to a regular payout of any earned annual and long-term awards whose performance periods had ended prior to the individual’s termination, and to a pro-rated payout (based on the individual’s number of full months of employment during the applicable performance period) for other outstanding annual and long-term incentive awards when and if payouts of such awards are subsequently earned and are made to participants who did not terminate their employment. Assuming that the named executive officers (other than Mr. Moore) terminated their employment as a result of death, disability or retirement on December 31, 2007, each executive officer would have received the same payout of the earned annual incentive compensation for 2007 that is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 26 and the same payout of long-term compensation for the performance units whose three-year performance period ended December 31, 2007 as reflected in the Stock Awards - Value Realized on Vesting column in the Option Exercises and Stock Vested Table on page 29. The reason for the same payouts is that the individual would have been employed throughout the entire performance period for the awards. If the named executive officer elects to exercise his options at the time of termination and, assuming that the price of our common stock was $36.29 (the closing price on December 31, 2007), then the value realized on the exercise of the options for the named executive officers would have been as follows: P.B. Delaney, $2,458,262; J.R. Hatfield, $178,882; D.P. Harris, $379,095; H.S. Forbes, $0 and P.L. Renfrow $0. In addition, for the outstanding grants of performance units whose performance periods end on December 31, 2008 and December 31, 2009 and assuming that the named executive officers (other than Mr. Moore) terminated their employment as a result of death, disability or retirement on December 31, 2007, that the applicable goals for such performance units were subsequently satisfied at target levels and that the price of OGE Energy’s Common Stock was $36.29 (the closing price on December 31, 2007) at the time payouts of such performance units occurred, then the named executive officers would be entitled to receive Common Stock of the Company having the following values at the time payout of such performance units occurred: P.B. Delaney, $818,717 for the performance units whose performance period ends December 31, 2008 and $242,320 for the performance units whose performance period ends December 31, 2009; J.R. Hatfield, $421,529 for the performance units whose performance period ends December 31, 2008 and $122,237 for the performance units whose performance period ends December 31, 2009; D.P. Harris, $208,456 for the performance units whose performance period ends December 31, 2008 and $74,564 for the performance units whose performance period ends December 31, 2009; H.S. Forbes $128,832 for the performance units whose performance period ends December 31, 2008 and $36,338 for the performance units whose performance period ends December 31, 2009; and P.L. Renfrow $95,990 for the performance units whose performance period ends December 31, 2008 and $35,697 for the performance units whose performance period ends December 31, 2009.

Mr. Delaney and Mr. Hatfield also are entitled to a death benefit equal to three times salary under a split dollar life insurance arrangement with a third party life insurance company. Under the arrangement, insurance proceeds in excess of that amount help fund benefits payable under the Retirement Restoration Plan. If Mr. Delaney or Mr. Hatfield terminates employment for a reason other than death, the death benefit coverage terminates. The

Company would then use the cash surrender value of the policy to help pay the benefit to which the employee is entitled under the Retirement Restoration Plan. Assuming that Mr. Delaney and Mr. Hatfield terminated their employment as a result of death on December 31, 2007, they would have been entitled to death benefits under this policy of $2,325,000 and $1,125,000, respectively.

Mr. Hatfield and Mr. Harris also are beneficiaries of split-dollar life insurance policies pursuant to which they are entitled to receive the cash surrender value in the event of termination of employment for other than death and the life insurance policy proceeds in the event of their death while employed by the Company. In each case, proceeds would first be utilized to reimburse the Company for premium payments. These premiums are included in the Summary Compensation Table on page 26. Assuming that Mr. Hatfield and Mr. Harris terminated their employment for reasons other than death on December 31, 2007, the cash surrender value of the policies, net of reimbursement of premiums, would have been $11,272 and $0, respectively. Assuming Mr. Hatfield and Mr. Harris terminated their employment as a result of death on December 31, 2007, they would have been entitled to death benefits under the policies, net of reimbursement of premiums, of $335,312 and $228,323, respectively.

In addition to the benefits described above, upon retirement, the executive officers will be entitled to receive the retirement benefits described in the Pension Benefits table on page 29 and the nonqualified deferred compensation benefits set forth in the Nonqualified Deferred Compensation table on page 31 as well as contributory lifetime retiree medical benefits if they were hired prior to February 1, 2000 and noncontributory lifetime retiree life insurance at 60% of pre-retirement levels but not more than $20,000 or less than $10,000.

As a result of his death in September 2007, Mr. Moore’s beneficiary was entitled to accrued salary, a death benefit of three times salary payable from insurance proceeds and prorated payments for annual and long-term incentive awards when and if payouts were subsequently earned and paid out to others. The amount of salary, death benefit and annual incentives paid to Mr. Moore and his beneficiary is reported in the Summary Compensation Table, while the payout of long-term incentive awards is reported in the Option Exercises and Stock Vested Table. In addition, Mr. Moore’s beneficiary received a distribution of his deferred compensation balance under the Deferred Compensation Plan, including a survivor benefit, as reported in the Nonqualified Deferred Compensation Table and distributions under the Company’s retirement plans as reported in the Pension Benefits Table.

SECURITY OWNERSHIP

The following table shows the number of shares of the Company’s Common Stock beneficially owned on March 1, 2008, by each Director, by each of the Executive Officers named in the Summary Compensation Table on page 26, and by all Executive Officers and Directors as a group and by each shareholder owning 5% or more of the Company's Common Stock:

	Number of Common		Number of Common
	Shares(1) (2) (3)		Shares(1) (2) (3)

Herbert H. Champlin	67,015	P.B. Delaney	242,523
Luke R. Corbett	48,396	J.R. Hatfield	62,076
John D. Groendyke	38,285	D.P. Harris	38,557
Kirk Humphreys	1,951	H.S. Forbes	1,763
Robert Kelley	54,164	P.L Renfrow	9,124
Linda Petree Lambert	6,894	S.E. Moore Estate	923,486
Robert O. Lorenz	12,053	All Executive Officers and	1,717,287
Leroy C. Richie	1,588	Directors as a group
Ronald H. White, M.D.	53,296	(29 persons)
J.D. Williams	29,768	Barclays Global Investors,	4,940,264
		N.A. (4)
		Barclays Global Fund
		Advisors (4)
		45 Fremont Street
		San Francisco,CA 94105

(1)

Ownership by each executive officer is less than 1.0% of the class, by each director other than Mr. Delaney is less than 0.07% of the class and, for all executive officers and directors as a group, is less than 1.9% of the class. Amounts shown include shares for which, in certain instances, an individual has disclaimed beneficial interest. Amounts shown for executive officers include 69,949 shares of Common Stock representing their interest in shares held under the Company’s Retirement Savings Plan and Officer’s Deferred Compensation Plan for which in certain instances they have voting power but not investment power.

(2)

Amounts shown for Messrs. Champlin, Corbett, Durrett, Groendyke, Humphreys, Kelley, Lorenz, Richie, White and Williams and Ms. Lambert include, 59,061; 42,910; 12,785; 1,951; 38,064; 9,053; 1,588; 46,196; 12,642 and 6,894 common stock units, respectively, under the 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, 2008, as follows: Mr. Champlin, 5,100 shares; Mr. Corbett, 5,100 shares; Mr. Groendyke, 0 shares; Mr. Humphreys, 0 shares; Mr. Kelley, 5,100 shares; Ms. Lambert, 0 shares; Mr. Lorenz, 0 shares; Mr. Richie, 0 shares; Dr. White, 5,100 shares; Mr. Williams, 5,100 shares; Mr. Delaney, 164,600 shares; Mr. Hatfield, 14,068 shares; Mr. Harris, 23,301 shares; Mr. Forbes, 0 shares; Mr. Renfrow, 0 shares; Mr. Moore, 761,200 shares.

(4)

Based on a Schedule 13G filed on February 6, 2008, Barclays Global Investors, N.A. and Barclays Global Fund Advisors, along with certain other affiliates, are deemed to beneficially own these shares because they are held in trust accounts for the economic benefit of the beneficiaries of those accounts. These shares represented approximately 5.37% of our outstanding common stock on March 1, 2008.

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

EQUITY COMPENSATION PLAN INFORMATION

The following table provides certain information as of December 31, 2007 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
	Outstanding	of Outstanding	(excluding securities
Plan Category	Options	Options	reflected in Column A)

Equity Compensation Plans
Approved by
Shareowners (1)	1,138,917	$21.34	1,759,162(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 OGE Energy Corp. 2003 Stock Incentive Plan can take the form of stock options, stock appreciation rights, restricted stock or performance units. Does not include awards under the 2008 Stock Incentive Plan that is being submitted to shareowners for their approval at this year’s Annual Meeting.

PROPOSAL NO. 3 - APPROVAL OF

OGE ENERGY CORP. 2008 STOCK INCENTIVE PLAN

The Board of Directors has approved and recommended the adoption of the OGE Energy Corp. 2008 Stock Incentive Plan (the “Stock Incentive Plan”), subject to approval by the Company’s shareowners. The Stock Incentive Plan is intended to replace the OGE Energy Corp. 2003 Stock Incentive Plan, which was approved by shareowners at the 2003 annual meeting (the “current stock incentive plan”). It is anticipated that no further awards will be granted under the current stock incentive plan.

The purpose of the Stock Incentive Plan is to enable the Company and its subsidiaries and other Affiliates (as defined in the Stock Incentive Plan) to attract, retain and motivate non-employee directors, officers and employees and to provide the Company and its Affiliates with the ability to provide incentives more directly linked to the profitability of the Company’s businesses and increases in shareowner value and the enhancement of performance relating to customers.

The Stock Incentive Plan has been designed to comply with limits imposed by the tax laws on the ability of a public company to claim tax deductions for compensation paid to certain highly compensated executives. Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), generally denies a corporate tax deduction for annual compensation exceeding $1,000,000 paid to the principal executive officer and the three other most highly compensated officers (other than the principal financial officer) of a public company (“Covered Employees”). Certain types of compensation, including performance-based compensation, are generally excluded from this deduction limit. In an effort to ensure that stock awards under the Stock Incentive Plan will qualify as performance-based compensation, which is generally deductible, the Stock Incentive Plan is being submitted to shareowners for approval at the Annual Meeting. While the Company believes compensation payable pursuant to the Stock Incentive Plan generally will be deductible for federal income tax purposes, under certain circumstances such as death, disability and change of control (all as defined in the Stock Incentive Plan), compensation not qualified under Section 162(m) of the Code may be payable. By approving the Stock Incentive Plan, the shareowners will be approving, among other things, the performance measures, eligibility requirements and limits on various stock awards contained therein.

Set forth below is a summary of certain important features of the Stock Incentive Plan. This summary is qualified in its entirety by reference to the actual plan attached hereto as Annex A.

Administration. The Stock Incentive Plan will be administered by the Compensation Committee of the Board of Directors of the Company or such other committee of the Board as the Board may from time to time designate, which will be composed solely of not less than two “disinterested persons” for purposes of Rule 16b-3 under the Securities Exchange Act of 1934 who also qualify as “outside directors” for purposes of Section 162(m) of the Code. Among other things, the Compensation Committee will have the authority, subject to the terms of the Stock Incentive Plan, to select non-employee directors, officers and employees to whom awards may be granted, to determine the type of award as well as the number of shares of Common Stock to be covered by each award, and to determine the terms and conditions of any such awards. The Compensation Committee also will have the authority to adopt, alter and repeal such administrative rules, guidelines and practices governing the Stock Incentive Plan as it deems advisable, to construe and interpret the terms and provisions of the Stock Incentive Plan and any awards issued thereunder and to otherwise supervise the administration of the Stock Incentive Plan. All decisions made by the Compensation Committee pursuant to the Stock Incentive Plan will be final and binding.

Eligibility. Officers and employees of the Company and its Affiliates designated by the Compensation Committee who are responsible for or contribute to the management, growth and profitability of the Company and nonemployee directors of the Company or an Affiliate are eligible to be granted awards under the Stock Incentive Plan.

Plan Features. The Stock Incentive Plan authorizes the issuance of up to 2,750,000 shares of Common Stock pursuant to the grant or exercise of incentive stock options (“ISOs”), nonqualified stock options, stock appreciation rights (“SARs”), restricted stock and performance units, but not more than 600,000 shares may be issued as restricted stock. The closing price of the Common Stock on March 24, 2008 was $30.53. All 2,750,000 shares will be available for issuance upon exercise of ISOs. No single participant may be granted awards pursuant to the Stock Incentive Plan covering in excess of 500,000 shares (5,000 shares for non-employee directors) of Common Stock in any one calendar year and all such awards may be granted as stock options or SARs, if any. No participant may be granted performance units in any one calendar year payable in cash in an amount that would exceed $1,000,000 ($15,000 for non-employee directors). Subject to the foregoing limits, the shares available under the Stock Incentive Plan can be divided among the various types of awards and among the participants as the Compensation Committee sees fit. The shares subject to grant under the Stock Incentive Plan are to be made available from authorized but unissued shares or from treasury shares. Awards may be granted for such terms as the Compensation Committee may determine, except that the term of a stock option may not exceed ten years from its date of grant. Awards will not be transferable, except by will and the laws of descent and distribution and, in the case of nonqualified stock options and any related SARs, if permitted by the Compensation Committee, as a gift to an optionee’s children or to a charitable organization described in Code Section 170(c). The Compensation Committee will have broad authority to fix the terms and conditions of individual agreements with participants.

Description of Awards. As indicated above, several types of stock-related grants can be made under the Stock Incentive Plan. The Compensation Committee will have the authority to determine the non-employee directors, officers and employees to whom and the time or times at which awards may be granted. A summary of these grants is set forth below:

Stock Options. The Stock Incentive Plan authorizes the Compensation Committee to grant options to purchase Common Stock at an option price (the “option price”) which cannot be less than 100% of the fair market value of such stock on the date of grant. The Stock Incentive Plan permits optionees, with the approval of the Compensation Committee, to pay the option price of options in cash, stock (valued at its fair market value on the date of exercise) or a combination thereof. As noted above, options may be granted either as ISOs or nonqualified options. The principal difference between ISOs and nonqualified options is their tax treatment. See “--Federal Income Tax Consequences.”

SARs. The Stock Incentive Plan authorizes the Compensation Committee to grant SARs in conjunction with all or part of any stock option granted under the Stock Incentive Plan. An SAR entitles the holder to receive upon exercise the excess of the fair market value of a specified number of shares of Common Stock at the time of exercise over generally the option price for such shares specified in the related stock option. Such amount will be paid to the holder in shares of Common Stock (valued at its fair market value on the date of exercise), cash or a combination thereof, as the Compensation Committee may determine. An SAR may be granted in conjunction with a contemporaneously granted ISO or a previously or contemporaneously granted nonqualified option. Since the exercise of an SAR is an alternative to the exercise of an option, the option will be canceled to the extent that the SAR is exercised and the SAR will be canceled to the extent the option is exercised.

Restricted Stock. The Stock Incentive Plan authorizes the Compensation Committee to grant restricted stock to individuals with such restriction periods as the Compensation Committee may designate. The Compensation Committee may, prior to granting shares of restricted stock, designate certain participants as “Covered Employees” upon determining that such participants are or are expected to be “covered employees” within the meaning of Section 162(m)(3) of the Code, and will provide that restricted stock awards to these Covered Employees cannot vest unless applicable performance goals established by the Compensation Committee within the time period prescribed by Section 162(m) of the Code are satisfied. These performance goals must be based on the attainment by the Company, one or more Affiliates or one or more businesses or functional units thereof of: specified levels of total shareholder return; return on capital; earnings per share; market share; stock price; sales; costs; net operating income; net income; return on assets; earnings before income taxes, depreciation and amortization; return on total assets employed; capital expenditures; earnings before income taxes; economic value added; cash flow; cash available for distribution; retained earnings; return on equity; results of customer satisfaction surveys; aggregate product price and other product price measures; safety record; service reliability; demand-side management (including conservation and load management); operating and/or maintenance costs management (including operation and maintenance expenses per Kilowatt-hour (“Kwh”)); and energy production availability.

At the time of establishing a performance goal, the Compensation Committee shall specify the manner in which the performance goal shall be calculated. In so doing, the Compensation Committee may exclude the impact of certain specified events from the calculation of the performance goal. Such performance goals also may be based on the attainment of specified levels of performance of the Company, one or more Affiliates or one or more businesses or functional units thereof under one or more of the measures described above relative to the performance of other corporations or indices. Performance goals based on the foregoing factors are hereinafter referred to as “Performance Goals.” With respect to Covered Employees, all Performance Goals must be objective performance goals satisfying the requirements for “performance-based compensation” within the meaning of Section 162(m)(4) of the Code. The Compensation Committee also may condition the vesting of restricted stock awards to participants who are not Covered Employees upon the satisfaction of these or other applicable performance goals. The provisions of restricted stock awards (including any applicable Performance Goals) need not be the same with respect to each participant. During the restriction period, the Compensation Committee may require that the stock certificates evidencing restricted shares be held by the Company. Restricted stock may not be sold, assigned, transferred, pledged or otherwise encumbered. Other than these restrictions on transfer and any other restrictions the Compensation Committee may impose, the participant will have all the rights of a holder of stock holding the class or series of stock that is the subject of the restricted stock award.

Performance Units. The Stock Incentive Plan authorizes the Compensation Committee to grant performance units. Performance units may be denominated in shares of Common Stock or cash, or may represent the right to receive dividend equivalents with respect to shares of Common Stock, as determined by the Compensation

Committee. Performance units will be payable in cash or shares of Common Stock or a combination thereof if applicable Performance Goals (based on one or more of the measures described in the section entitled “-- Restricted Stock” above) determined by such committee are achieved during an award cycle. An award cycle will consist of a period of consecutive fiscal years or portions thereof designated by the Compensation Committee over which performance units are to be earned. After the conclusion of a particular award cycle, the Compensation Committee will determine the number of performance units granted to a participant which have been earned in view of actual performance against applicable Performance Goals and prior to the 15th day of the third month after the end of the award cycle shall deliver to such participant cash and/or the number of shares of Common Stock equal to the value of performance units determined by the Compensation Committee to have been earned.

The Compensation Committee will have the authority to determine the non-employee directors, officers and employees to whom and the time or times at which performance units will be awarded, the form and number of performance units to be awarded to any participant, the duration of the award cycle and any other terms and conditions of an award. In the event that a participant’s employment is terminated due to death, disability or retirement, the Compensation Committee will have the discretion to pay a prorated award, based on the participant’s number of months of service during the award cycle and achievement of performance goals over the entire award cycle.

Duration, Amendment And Discontinuance. The Stock Incentive Plan will terminate on June 30, 2018. Awards outstanding as of such date will not be affected or impaired by the termination of the Stock Incentive Plan. The Stock Incentive Plan may be amended, altered or discontinued by the Board, but no amendment, alteration or discontinuance may be made which would (i) impair the rights of an optionee under an option or a recipient of an SAR, restricted stock award or performance unit award previously granted without the optionee’s or recipient’s consent, except such an amendment made to qualify the Stock Incentive Plan for the exemption provided by Rule 16b-3 or to comply with or qualify for an exemption from Code Section 409A or (ii) disqualify the Stock Incentive Plan from the exemption provided by Rule 16b-3. Except as expressly provided in the Stock Incentive Plan, the Stock Incentive Plan may not be amended without shareowner approval to the extent such approval is required by law or agreement. The Compensation Committee also may amend the terms of any option or other award previously granted, except that (i) no such amendment shall impair the rights of any holder without the holder’s consent except such an amendment made to cause the Plan or award to qualify for the exemption provided by Rule 16b-3 or to comply with or qualify for an exemption from Code Section 409A and (ii) no such amendment shall lower the option exercise price of an option other than in certain specified instances involving a change in capitalization or similar transaction.

Changes In Capitalization; Change Of Control. The Stock Incentive Plan provides that, in the event of any change in corporate capitalization, such as a stock split or dividend, or a corporate transaction, such as any merger, consolidation, share exchange, separation, spin-off or other distribution of stock or property of the Company, or any reorganization or partial or complete liquidation of the Company, the Compensation Committee or the Board will make such substitutions or adjustments in the number and kind of shares reserved for issuance under the Stock Incentive Plan, in the aggregate or to any participant, in the number, kind and option price of shares subject to outstanding stock options and SARs, and in the number and kind of shares subject to other outstanding awards granted under the Stock Incentive Plan as may be determined to be appropriate by the Compensation Committee or the Board, in its sole discretion. The Stock Incentive Plan also provides that in the event of a change of control (as defined in the Stock Incentive Plan which is attached hereto as Annex A) of the Company (i) any SARs and stock options outstanding as of the date of the change of control which are not then exercisable and vested will become fully exercisable and vested, (ii) the restrictions applicable to restricted stock will lapse and such restricted stock shall become free of all restrictions and fully vested and (iii) all performance units will be considered to be earned and payable in full in an amount that will be equal to the number of performance units that would have been payable had the performance goals been met at a level that would have resulted in 100% payout of the performance units awarded, and any restrictions will lapse and such performance units will be settled in cash as promptly as practicable but in no event later than the 15th day of the third month after the occurrence of the change of control. The holders of options, unless the Compensation Committee shall determine otherwise at grant, will have the right, for a period of 60 days after the date of the change of control, to surrender all or part of such options in exchange for a cash payment based on the excess of the fair market value per share on the date of exercise over the option price.

Federal Income Tax Consequences. The following discussion is intended only as a brief summary of the federal income tax rules relevant to stock options, SARs, restricted stock and performance units. The laws governing the tax aspects of awards are highly technical and such laws are subject to change. Awards under the Stock Incentive Plan are not intended to provide for the deferral of compensation within the meaning of Code Section 409A, and therfore Section 409A of the Code does not apply to awards under the Stock Incentive Plan.

Nonqualified Options And SARs. Upon the grant of a nonqualified option (with or without an SAR), the optionee will not recognize any taxable income and the Company will not be entitled to a deduction. Upon the exercise of such an option or an SAR, the excess of the fair market value of the shares acquired on the exercise of the option over the option price (the “spread”), or the consideration paid to the optionee upon exercise of the SAR, will constitute compensation taxable to the optionee as ordinary income. In determining the amount of the spread or the amount of consideration paid to the optionee, the fair market value of the stock on the date of exercise is used. The Company, in computing its federal income tax, will generally be entitled to a deduction in an amount equal to the compensation taxable to the optionee.

ISOs. An optionee will not recognize taxable income on the grant or exercise of an ISO. However, the spread at exercise will constitute an item includible in alternative minimum taxable income, and thereby may subject the optionee to the alternative minimum tax. Such alternative minimum tax may be payable even though the optionee receives no cash upon the exercise of his ISO with which to pay such tax. An ISO will generally be disqualified from receiving ISO tax treatment under the Code if it is exercised more than three months following termination of employment. If, however, the optionee is disabled, such tax treatment is available for exercises occurring within one year following termination and, if the optionee dies while employed, this statutory time requirement for receiving ISO tax treatment is waived altogether.

Upon the disposition of shares of stock acquired pursuant to the exercise of an ISO after the later of (i) two years from the date of grant of the ISO or (ii) one year after the transfer of the shares to the optionee upon exercise (the “ISO Holding Period”), the optionee will recognize long-term capital gain or loss, as the case may be, measured by the difference between the stock’s selling price and the option price. The Company is not entitled to any tax deduction by reason of the grant or exercise of an ISO, or by reason of a disposition of stock received upon exercise of an ISO if the ISO Holding Period is satisfied. Different rules apply if the optionee disposes of the shares of stock acquired pursuant to the exercise of an ISO before the expiration of the ISO Holding Period.

Restricted Stock. A participant who is granted restricted stock may make an election (a “Section 83(b) election”) to have the grant taxed as compensation income at the date of receipt, with the result that any future appreciation (or depreciation) in the value of the shares of stock granted shall be taxed as capital gain (or loss) upon a subsequent sale of the shares. Any such Section 83(b) election must be made and filed with the IRS within 30 days of receipt in accordance with the regulations under Section 83(b) of the Code. If the participant does not make a Section 83(b) election, then the grant will be taxed as compensation income at the full fair market value on the date that the restrictions imposed on the shares expire. Unless a participant makes a Section 83(b) election, any dividends paid on stock subject to the restrictions are compensation income to the participant and compensation expense to the Company. The Company is generally entitled to an income tax deduction for any compensation income taxed to the participant, subject to the provisions of Section 162(m) of the Code.

Performance Units. A participant who has been granted a performance unit award will not realize taxable income until the applicable award cycle expires and the participant is in receipt of the stock and/or cash distributed in payment of the award, at which time such participant will realize ordinary income equal to the full fair market value of the shares delivered and/or the amount of cash paid. At that time, the Company generally will be allowed a corresponding tax deduction equal to the compensation taxable to the award recipient, subject to the provisions of Section 162(m) of the Code.

New Plan Benefits. Although the Compensation Committee has granted awards to certain individuals under the current stock incentive plan (see 2008 Awards below), it cannot be determined at this time what benefits or amounts, if any, will be allocated to or received by any persons or group of persons under the Stock Incentive Plan if the Stock Incentive Plan is adopted. Such determinations as to allocations are subject to the discretion of the Compensation Committee and as to receipt of payouts are dependent on future performance.

2008 Awards. The Compensation Committee in February 2008 granted performance units denominated in the following number of shares of Common Stock to the individuals and groups described below under the current stock incentive plan:

OGE ENERGY CORP. 2003 STOCK INCENTIVE PLAN


Name and Principal position	Dollar Value ($)	Number of Units (#)
P.B. Delaney, Chief Executive Officer	$1,588,750	46,935
J.R. Hatfield, Sr. Vice President and Chief Financial Officer	$387,989	11,462
D.P. Harris, Sr. Vice President, Chief Operating Officer OGE Energy and President, Enogex, Inc.	$713,998	21,093
H.S. Forbes, Controller and Chief Accounting Officer	$126,227	3,729
P.L. Renfrow, Vice President, Public Affairs	$114,007	3,368
Executive Group (18 persons)	$4,388,077	129,633
Non-Executive Director Group (10 persons)	$0	0
Non-Executive Officer Group (89 persons)	$3,820,650	112,870

Awards of performance units will be payable in shares of Common Stock. The participants will be entitled to receive from 0% to 200% of the performance units granted depending upon the level of achievement of performance goals set by the Compensation Committee during an award cycle commencing on January 1, 2008 and ending on December 31, 2010.

Vote Required. The affirmative vote of a majority of the votes entitled to be cast by the holders of the shares of the Company’s Common Stock represented at the Annual Meeting and entitled to vote thereon is required to approve the Stock Incentive Plan with respect to Section 162(m) of the Code. Abstentions from voting on this matter will be treated as votes against, while broker non-votes, if any, will be treated as shares not voted. Such vote will also satisfy the shareowner approval requirements of the New York Stock Exchange and Section 422 of the Code with respect to the grant of ISOs.

THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS A VOTE “FOR” APPROVAL OF THE 2008 STOCK INCENTIVE PLAN.

PROPOSAL NO. 4 - APPROVAL OF OGE ENERGY CORP. 2008 ANNUAL

INCENTIVE COMPENSATION PLAN

The Board of Directors has approved and recommended the adoption of an annual incentive compensation plan subject to approval by shareowners. The OGE Energy Corp. 2008 Annual Incentive Compensation Plan (the “Annual Plan”) is intended to replace the OGE Energy Corp. 2003 Annual Incentive Compensation Plan, which was approved by shareowners at the 2003 annual meeting (the “current annual plan”). As discussed below, the Annual Plan is designed to comply with Section 162(m) of the Code and the Annual Plan will not become effective unless the shareowner approval described below is obtained.

The purpose of the Annual Plan is to maximize the efficiency and effectiveness of the operations of the Company and its subsidiaries by providing incentive compensation opportunities to certain key executives and managers responsible for operational effectiveness and to link further the financial interests and objectives of employees with those of the Company and its shareowners. The Annual Plan provides for the payment of annual cash bonuses based on Company performance and individual performance.

The Annual Plan is designed to take into account Section 162(m) of the Code, which, as explained above regarding Proposal No. 3, generally denies a corporate tax deduction for annual compensation exceeding $1,000,000 paid to the principal executive officer and the three other most highly compensated officers (other than

the principal financial officer) of a public company (“Covered Employees”). Certain types of compensation, including performance-based compensation, are excluded from this deduction limit. In an effort to ensure that certain compensation payable under the Annual Plan to certain executives will qualify as performance-based compensation that is generally tax-deductible, the Annual Plan is being submitted to shareowners of the Company for approval at the Annual Meeting. By approving the Annual Plan, the shareowners will be approving, among other things, the performance measures, eligibility requirements and annual incentive award limits contained therein. The Annual Plan provides for the establishment and payment of Target Company Awards and Target Individual Awards. Target Individual Awards payable under the Annual Plan will not qualify as “performance-based compensation” under Section 162(m) of the Code and, thus, will count toward the annual $1,000,000 deduction limit. For this reason, the Annual Plan precludes the granting or payment of Target Individual Awards to participants who are or may be a Covered Employee and for whom the Compensation Committee intends amounts payable under an award to qualify as “performance-based compensation” under Code Section 162(m). If the shareowners approve the Stock Incentive Plan and the Annual Plan, the Compensation Committee believes that all compensation paid to executives will continue to be deductible by the Company in the foreseeable future.

Set forth below is a summary of certain important features of the Annual Plan. This summary is qualified in its entirety by reference to the actual plan attached hereto as Annex B.

Administration. The Annual Plan will be administered by the Compensation Committee, or such other committee of the Board as the Board may from time to time designate, which, to the extent Target Company Awards are intended to be exempt from Section 162(m) of the Code, will be composed solely of not less than two persons who qualify as “outside directors” for purposes of Section 162(m) of the Code. The Compensation Committee will have sole authority to make rules and regulations relating to the administration of the Annual Plan, and any interpretations and decisions of the Compensation Committee with respect to the Annual Plan will be final and binding.

Eligibility. Officers, executives or other key employees of the Company and its subsidiaries who, in the opinion of the Chief Executive Officer, can contribute significantly to the growth and profitability of the Company and its subsidiaries are eligible to be selected by the Compensation Committee to be granted awards under the Annual Plan. Specific criteria for participation shall be established by the Compensation Committee prior to the beginning of each incentive period (generally a calendar year), and selected employees will be notified in writing of their selection, and of their performance goals and related Target Company Awards and Target Individual Awards, as soon as practicable. Under certain circumstances, individuals who become eligible after an incentive period has commenced may participate in the Annual Plan. The Compensation Committee may withdraw its approval for participation in the plan with respect to an incentive period at any time during such period (except after a change of control occurs during an incentive period), and the employee will not be entitled to the payment of any Award for such incentive period. No participant or other employee shall have the right to participate in the Annual Plan for any incentive period, despite having been selected in a previous incentive period. No right or interest of any participant in the Annual Plan may be assigned, transferred, pledged or encumbered.

Description Of Awards. Target Company Awards. The Annual Plan permits the award of Target Company Awards (expressed as a percentage of base salary), which are established independent of the Target Individual Awards discussed below. On or before the 90th day of each incentive period and in any event before 25% or more of the incentive period has elapsed, the Compensation Committee will establish for each participant, who is to be granted a Target Company Award, the Target Company Award and specific objective performance goals for the incentive period, which will be based on one or more of the following relating to the Company, one or more of its subsidiaries, or one or more businesses or functional units thereof: total shareholder return; return on equity; return on capital; earnings per share; market share; stock price; sales; costs; net operating income; net income; return on assets; earnings before income taxes, depreciation and amortization; return on total assets employed; capital expenditures; earnings before income taxes; economic value added; cash flow; cash available for distribution; retained earnings; results of customer satisfaction surveys; aggregate product price and other product price measures; safety record; service reliability; demand-side management (including conservation and load management); operating and/or maintenance cost management (including operation and maintenance expenses per Kwh); and energy production availability performance measures (“Company Performance Goals”). At the time Target Company Awards are established, the Compensation Committee will specify the manner in which the Company Performance Goal(s) will be calculated. In so doing, the Compensation Committee may exclude the impact of certain specified events from the calculation of the Company Performance Goal(s). For example, if a Company Performance Goal were earnings per share, the Compensation Committee could, at the time the Company Performance Goals are established, specify that earnings per share are to be calculated without regard to any subsequent change in accounting standards required by the Financial Accounting Standards Board. Company Performance Goals may also

be based on the attainment of specified performance levels of the Company, any of its subsidiaries and/or one or more businesses or functional units thereof under one or more of the measures described above relative to the performance of other corporations or indices. Upon establishing the Target Company Awards, the Compensation Committee will establish a minimum level of achievement of the Company Performance Goals that must be met in order to receive any portion of such award.

The level of achievement of the Company Performance Goals at the end of the incentive period will determine the amount of each participant’s Target Company Award that such participant will receive (the “Earned Company Award”), which may exceed 100% of the participant’s Target Company Award. If the minimum level of achievement of Company Performance Goals for any incentive period is not met, no payment of an Earned Company Award will be made to the particular participant for that incentive period. To the extent that one or more minimum achievement levels are met or surpassed, and upon certification by the Compensation Committee that the Company Performance Goals have been satisfied and that any other material terms and conditions of the Target Company Award are met, payment of an Earned Company Award will be made to the participant for that incentive period. Payment will be made within the 2-½ month period after the end of the incentive period. The payment of all Earned Company Awards is subject to reduction or elimination by the Compensation Committee, in its sole discretion, until a change of control occurs. Except as set forth above, the Compensation Committee will have no additional discretion to modify the terms of Target Company Awards. The maximum amount payable to a participant for an Earned Company Award for any incentive period will not exceed $2,000,000.

Individual Performance Awards. The Annual Plan permits the award of Target Individual Awards (expressed as a percentage of base salary), which are established independent of the Target Company Awards discussed above. At the beginning of each incentive period, the Chief Executive Officer will recommend individual performance goals (which may be based in whole or in part on one or more Company Performance Goals) for each plan participant who is to be granted a Target Individual Award. The Compensation Committee will consider and approve or modify the recommendations as appropriate. The Chief Executive Officer may adjust individual performance goals if he determines external changes or other unanticipated conditions have materially affected the fairness of the goals. The level of achievement of the individual performance goals at the end of the incentive period will determine the amount of each participant’s Target Individual Award that such participant will receive (the “Earned Individual Award”), which may range from 0% to 175% of the participant’s Target Individual Award and cannot exceed $350,000. The payment of all Earned Individual Awards is subject to approval by the Compensation Committee, and will in no way be contingent upon the attainment of, or the failure to attain, the Company Performance Goals for the Target Company Awards granted to participants. Payment will be made within the 2-½ month period after the end of the incentive period.

Because the individual performance goals described above are not required to be objective in nature, the award of Target Individual Awards and the payout of Earned Individual Awards do not qualify as “performance-based compensation” as defined in Section 162(m) of the Code. In order to ensure compliance with Section 162(m), the Annual Plan precludes the granting of Target Individual Awards or payout of Earned Individual Awards to participants who are or may be Covered Employees and for whom the Compensation Committee intends amounts payable under an award to qualify as “performance-based compensation” under Code Section 162(m). However, the Compensation Committee desires to retain the ability to evaluate other key employees on a subjective basis through Target Individual Awards.

Separation from Service. In the event of separation from service (as defined in Code Section 409A) due to death, total and permanent disability or retirement, and such separation does not occur within 24 months after a change of control, any Earned Awards (Earned Individual Awards and/or Earned Company Awards) for the incentive period in which the separation occurs will be prorated to reflect participation prior to separation from service. In the event of a separation from service for any other reason, and such separation does not occur within 24 months after a change of control, all of a participant’s rights to an Earned Award for the incentive period then in progress will be forfeited; provided that, except in the event of termination for cause, the Compensation Committee may, in its discretion, pay a prorated award for the portion of the incentive period that the participant was employed.

Change of Control. If any participant incurs a separation from service voluntarily or involuntarily for any reason other than for cause within 24 months after a change of control (as defined in the Annual Plan which is attached as Annex B), the Target Company Award and the Target Individual Award established for the participant for the incentive period in progress at the time of termination, which is prorated for the portion of the incentive period the participant is employed, will be paid to the participant within 10 business days. If, however, the participant is a “specified employee” (as defined in Code Section 409A) at the time of separation, such amount will be deferred and paid on the first day of the seventh month following separation or on earlier death.

Amendment and Discontinuance. Subject to the provisions of the Plan, the Board of Directors of the Company has absolute discretion to amend, modify, suspend or terminate the Annual Plan at any time.

New Plan Benefits. Although the Compensation Committee has awarded target company awards to certain individuals under the current annual plan (see 2008 Awards, below), it cannot be determined at this time what benefits or amounts, if any, will be allocated to or received by any persons or group of persons under the Annual Plan if the plan is adopted. Such determinations as to allocations are at the discretion of the Compensation Committee and as to receipt of payouts is dependent upon future performance. However, the benefits and amounts payable to certain executive officers under the current annual plan for 2007 and prior years are set forth in the non-equity incentive plan compensation column of the Summary Compensation Table on page 26 of this proxy statement.

2008 Awards. The Compensation Committee in November 2007 awarded target company awards for 2008 under the current annual plan to the following individuals and groups described below:

OGE ENERGY CORP. 2003 ANNUAL INCENTIVE PLAN

Name and

Principal position

Dollar Value of Target Awards

($)

P.B. Delaney,

Chief Executive Officer

$658,750

J.R. Hatfield,

Sr. Vice President
and Chief Financial Officer

$213,400

D.P. Harris,

Sr. Vice President, Chief
Operating Officer OGE Energy and

President, Enogex, Inc.

$357,000

H.S. Forbes,

Controller and Chief Accounting Officer

$80,325

P.L. Renfrow,

Vice President, Public Affairs

$79,800

Executive Group

(18 persons)

$2,368,875

Non-Executive Director Group

(10 persons)

Non-Executive Officer Group

(96 persons)

$3,564,863

The awards were granted for the incentive period commencing January 1, 2008 and ending December 31, 2008, and their payout is dependent upon individual and Company performance. Depending on such performance, the payout may be up to 150% of the Target Awards. In the event that the Annual Plan is not approved by the shareowners at the Annual Meeting, these awards will not be affected.

Vote Required. The affirmative vote of a majority of the shares of Common Stock entitled to vote and present in person or by proxy at the Annual Meeting is required for the approval of the adoption of the Annual Plan with respect to Section 162 (m) of the Code. Abstentions from voting on this matter are treated as votes against, while broker nonvotes are treated as shares not voted.

THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS THAT YOU VOTE “FOR” THE APPROVAL OF THE 2008 ANNUAL INCENTIVE COMPENSATION PLAN.

PROPOSAL NO. 5 - SHAREOWNER PROPOSAL TO ELIMINATE THE CLASSIFICATION OF THE TERMS OF DIRECTORS

Gerald R. Armstrong, 820 Sixteenth Street, No. 705, Denver, Colorado, 80202, beneficial owner of 79.9 shares, has given notice that he intends to present for action at the Annual Meeting the following resolution:

RESOLUTION

That the shareholders of OGE ENERGY CORP. request its Board of Directors to take the steps necessary to eliminate classification of terms of its Board of Directors to require that all Directors stand for election annually. The Board declassification shall be completed in a manner that does not affect the unexpired terms of the previously-elected Directors.

STATEMENT

The proponent believes the election of directors is the strongest way that shareholders influence the directors of any corporation. Currently, our board of directors is divided into three classes with each class serving three-year terms. Because of this structure, shareholders may only vote for one-third of the directors each year. This is not in the best interest of shareholders because it reduces accountability.

U.S. Bancorp, Associated Banc-Corp, Piper-Jaffray Companies, Fifth-Third Bancorp, Pan Pacific Retail Properties, Qwest Communications International, Xcel Energy, Greater Bay Bancorp, North Valley Bancorp, Pacific Continental Corporation, Regions Financial Corporation, CoBiz Financial Inc., Marshall & Illsley Corporation, and Wintrust Financial, Inc., are among the corporations electing directors annually because of the efforts of the proponent.

The performance of our management and our Board of Directors is now being more strongly tested due to economic conditions and the accountability for performance must be given to the shareholders whose capital has been entrusted in the form of share investments.

A study by researchers at Harvard Business School and the University of Pennsylvania’s Wharton School titled “Corporate Governance and Equity Prices” (Quarterly Journal of Economics, February, 2003), looked at the relationship between corporate governance practices (including classified boards) and firm performance. The study found a significant positive link between governance practices favoring shareholders (such as annual directors election) and firm value.

While management may argue that directors need and deserve continuity, management should become aware that continuity and tenure may be best assured when their performance as directors is exemplary and is deemed beneficial to the best interests of the corporation and its shareholders.

The proponent regards as unfounded the concern expressed by some that annual election of all directors could leave companies without experienced directors in the event that all incumbents are voted out by shareholders. In the unlikely event that shareholders do vote to replace all directors, such a decision would express dissatisfaction with the incumbent directors and reflect a need for change.

If you agree that shareholders may benefit from greater accountability afforded by annual election of all directors, please vote “FOR” this proposal.

THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL.

The Board of Directors does not believe that this proposal is in the best interest of OGE Energy shareowners. The Board believes that it is important this proposal should not be implemented, and therefore recommends a vote against the proposal.

The current classified board provision has been in the articles of incorporation and by-laws of the Company and its predecessor since 1986. It was approved by the shareowners of the Company (which at that time was Oklahoma Gas and Electric Company) in 1986 and was included as part of the transaction subsequently approved by shareowners in 1995 relating to the formation of the Company as a holding company. The Company’s articles of incorporation and by-laws, as approved by the shareowners, ultimately would require the affirmative vote of the holders of at least 80 percent of the Company’s outstanding Common Stock to change the existing classified board provision, even if the Company’s Board of Directors supported the proposal, which it does not.

A classified board provides enhanced continuity and stability in the Board’s business strategies and policies. With a classified board, two-thirds of the directors will always have had prior experience and familiarity with the business and affairs of OGE Energy. This enables the directors to build on past experience and plan for a reasonable period into the future. This facilitates the Board’s ability to focus on long-term strategy and long-term performance.

Moreover, a classified board helps protect shareowner value in the face of a coercive takeover attempt. Absent a classified board, a potential acquirer could gain control of the Company by replacing a majority of the Board with its own slate of nominees at a single annual meeting by a simple majority of the votes cast, and without paying any premium to OGE Energy’s shareowners. By contrast, the presence of a classified board and other protections encourage hostile shareowners who may seek to acquire control of OGE Energy to initiate arm’s-length discussions with management and the Board, who may be in a position to negotiate a higher price or more favorable terms for shareowners or to seek to prevent a takeover that the Board believes is not in the best interest of shareowners. The fact that the entire Board could not be removed in a single proxy fight would allow directors to weigh remaining independent against accepting the offer, or a competing offer, from a position of strength.

The proponent references a study finding a significant positive link between governance practices (such as annual election of all directors as contrasted to classified boards) and firm value. A more recent report (Bates, Becher and Lemmon, Board Classification and Managerial Entrenchment: Evidence from the Market for Corporate Control (April 2007)) reaches a different view, stating:

In closing, we note that the research to date has done little to empirically evaluate the potential shareholder benefits associated with classified board provisions or establish the causal nature of the relation between board classification and firm value. In this light we suggest a more circumspect policy approach be adopted by some governance practitioners and academics whose recent calls for the abolition of this common governance provision seem unwarranted and potentially damaging for shareholders.

This report also states:

Overall, the evidence is inconsistent with the view that board classification is associated with managerial entrenchment and instead suggests that classification improves the relative bargaining power of target managers on behalf of their constituent shareholders.

In the Company’s view, by reducing the threat of an abrupt change in the composition of the entire Board, the classified board permits a more orderly process for your directors to consider any and all alternatives to maximize shareowner value.

Proponents of declassified boards would have shareowners believe that the only way to ensure director independence and accountability is to declassify the board of directors. This is false. Your Board is committed to corporate accountability and believes that such accountability depends on the selection of responsible and experienced individuals, not on whether they serve one year or three year terms. Moreover, shareowners have a variety of tools at their disposal to ensure that directors, even directors who are elected on a classified basis, are accountable to shareowners. These tools include withholding votes from directors who are standing for election, publicity campaigns and meeting with directors to express shareowner concerns. Shareowners have successfully used these accountability tools with a number of companies.

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 approval of this shareowner proposal. Abstentions from voting in this matter are treated as votes “AGAINST.”

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” THIS PROPOSAL FOR THE REASONS DESCRIBED ABOVE. PROXIES SOLICITED BY THE BOARD OF DIRECTORS WILL BE VOTED “AGAINST” THIS PROPOSAL UNLESS A SHAREOWNER HAS INDICATED OTHERWISE IN VOTING THE PROXY.

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 set forth in the immediately succeeding sentence, to our knowledge, all of our officers and directors subject to such reporting obligations satisfied their reporting obligations in full in 2007. During 2007, Mr. Donald Rowlett, Chief Accounting Policy Officer, and Mr. Gary Huneryager, Vice President Internal Audits, each filed one Form 4 approximately one week late and Mr. Craig Johnston, Vice President Corporate Strategic Planning and Marketing, filed a Form 3 approximately one week late.

SHAREOWNER PROPOSALS

Any shareowner proposal intended to be included in the proxy statement for the Annual Meeting in 2009 must be received by the Company on or before December 3, 2008. 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 2009 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:

•

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,

•

your name and address,

•

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

•

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 Summary Annual Report to Shareowners and proxy statement, unless one or more of these shareowners notifies us that they would like to continue to receive individual copies. This will reduce our printing costs and postage fees. Shareowners who participate in householding will continue to receive separate proxy cards. Also, householding will not in any way affect dividend check or dividend reinvestment statement mailings.

If you and other shareowners of record with whom you share an address currently receive multiple copies of our Summary Annual Report to Shareowners and/or proxy statement, or if you hold stock in more than one account, and in either case, you would like to receive only a single copy of the Summary Annual Report to Shareowners or proxy statement for your household, please contact BNY Mellon Shareowner Services; P.O. Box 358035, Pittsburgh, PA 15252-8035 or phone toll free 1-888-216-8114.

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

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

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.

Annex A

OGE ENERGY CORP. 2008 STOCK INCENTIVE PLAN

Section 1. Purposes/Definitions.

The purpose of the Plan is to give the Company and its Affiliates a competitive advantage in attracting, retaining and motivating non-employee directors, officers and employees and to provide the Company and its Affiliates with the ability to provide incentives more directly linked to the profitability of the Company’s businesses, increases in shareowner value and enhancement of performance relative to customers.

For purposes of the Plan, the following terms are defined as set forth below:

a.	“Affiliate” means (i) a corporation at least 50 percent of the common stock or voting power of which is owned directly or indirectly by the Company, and (ii) any other corporation or other entity controlled by the Company and designated by the Committee from time to time.

b.	“Award” means a Stock Appreciation Right, Stock Option, Restricted Stock or Performance Unit.

c.	“Award Cycle” shall mean a period of consecutive fiscal years or portions thereof designated by the Committee over which Performance Units are to be earned.

d.	“Board” means the Board of Directors of the Company.

e.	“Change of Control” has the meaning set forth in Section 9(b).

f.	“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor thereto.

g.	“Commission” means the Securities and Exchange Commission or any successor agency.

h.	“Committee” means the Committee referred to in Section 2.

i.	“Common Stock” means common stock, par value $.01 per share, of the Company.

j.	“Company” means OGE Energy Corp., an Oklahoma corporation.

“Covered Employee” shall mean a participant designated by the Committee prior to the grant of shares of Restricted Stock or Performance Units who is or may be a “covered employee” within the meaning of Section 162(m)(3) of the Code in the year in which such Restricted Stock or Performance Units are taxable to such participant and for whom the Committee intends amounts payable with respect to such Awards to qualify under the performance-based compensation exemption of Section 162(m)(4)(C) of the Code.

l.	“Disability” means permanent and total disability as determined under procedures established by the Committee for purposes of the Plan.

m.	“Disinterested Person” means a member of the Board who qualifies as a non-employee director as defined in Rule 16b-3, as promulgated by the Commission under the Exchange Act, or any successor definition adopted by the Commission, and as an “outside director” for purposes of Section 162(m).

n.	“Early Retirement” of an employee means Termination of Employment at a time when the employee is entitled to early retirement benefits pursuant to the early retirement provisions of the applicable defined benefit pension plan of his or her employer.

o.	“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and any successor thereto.

p.	“Fair Market Value” means, as of any given date, the mean between the highest and lowest reported sales prices of the Common Stock on such date on the New York Stock Exchange Composite Tape (or, if not

A-1

listed on such exchange, on any other national securities exchange on which the Common Stock is listed or on NASDAQ) or, if there are no sales on such date, on the next preceding trading day during which a sale occurred. If such Common Stock is not readily tradable on an established securities market, the Fair Market Value of the Common Stock will be determined by the Committee in good faith using the reasonable application of a reasonable valuation method consistent with Code Section 409A and the regulations promulgated thereunder.

q.	“Incentive Stock Option” means any Stock Option designated as, and qualified as, an “incentive stock option” within the meaning of Section 422 of the Code.

r.	“Non-Qualified Stock Option” means any Stock Option that is not an Incentive Stock Option.

“Normal Retirement” means (i) with respect to an employee, Termination of Employment at a time when the employee is entitled to normal retirement benefits pursuant to the applicable defined benefit pension plan of his or her employer and (ii) with respect to a non-employee director, retirement from the Board or board of directors of the Affiliate on which he or she serves, pursuant to the applicable rules for such Board or board.

“Performance Goals” means the performance goals established by the Committee in writing prior to the grant of Restricted Stock or Performance Units that are based on the attainment of goals by the Company, one or more Affiliates or one or more business or functional units thereof relating to one or more of the following: total shareholder return; return on capital; earnings per share; market share; stock price; sales; costs; net operating income; net income; return on assets; earnings before income taxes, depreciation and amortization; return on total assets employed; capital expenditures; earnings before income taxes; economic value added; cash flow; cash available for distribution; retained earnings; return on equity; results of customer satisfaction surveys; aggregate product price and other product price measures; safety record; service reliability; demand-side management (including conservation and load management); operating and/or maintenance costs management (including operation and maintenance expenses per Kwh); and energy production availability. At the time of establishing a Performance Goal, the Committee shall specify the manner in which the Performance Goal shall be calculated. In so doing, the Committee may exclude the impact of certain specified events from the calculation of the Performance Goal. Such Performance Goals also may be based upon the attainment of specified levels of performance of the Company, one or more Affiliates or one or more business or functional units thereof under one or more of the measures described above relative to the performance of other corporations or indices. With respect to Covered Employees, all Performance Goals shall be objective performance goals satisfying the requirements for “performance-based compensation” within the meaning of Section 162(m)(4) of the Code, and shall be set by the Committee within the time period prescribed by Section 162(m) and related regulations.

u.	“Performance Units” means an award made pursuant to Section 8.

v.	“Plan” means the OGE Energy Corp. 2008 Stock Incentive Plan, as set forth herein and as hereinafter amended from time to time.

w.	“Restricted Stock” means an Award granted under Section 7.

x.	“Retirement” means Normal or Early Retirement.

y.	“Rule 16b-3” means Rule 16b-3, as promulgated by the Commission under Section 16(b) of the Exchange Act, as amended from time to time.

z.	“Section 162(m)” means Section 162(m) of the Code, as amended from time to time.

aa.	“Stock Appreciation Right” means a right granted under Section 6.

bb.	“Stock Option” means an option granted under Section 5 to purchase shares of Common Stock.

cc.	“Termination of Employment” means (i) with respect to an employee, the termination of participant’s employment with the Company and any Affiliate and (ii) with respect to a non-employee director, termi-

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nation of service on the Board and the board of directors of any Affiliate, as applicable, on which he or she serves. A participant employed by, or a non-employee director of, an Affiliate shall also be deemed to incur a Termination of Employment if the Affiliate ceases to be an Affiliate and the participant does not immediately thereafter become or remain an employee, or non-employee director, as the case may be, of the Company or another Affiliate.

In addition, certain other terms that are defined herein shall have the definitions so ascribed to them.

Section 2. Administration.

The Plan shall be administered by the Compensation Committee of the Board or such other committee of the Board as the Board may from time to time determine, which committee, to the extent required to comply with Rule 16-3 and Section 162(m), shall be composed solely of not less than two Disinterested Persons, each of whom shall be appointed by and serve at the pleasure of the Board. The Committee shall have plenary authority to grant Awards pursuant to the terms of the Plan to non-employee directors, officers and employees of the Company or its Affiliates. Among other things, the Committee shall have the authority, subject to the terms of the Plan:

(a)	to select the non-employee directors, officers and employees to whom Awards may from time to time be granted;

(b)	to determine whether and to what extent Incentive Stock Options, Non-Qualified Stock Options, Stock Appreciation Rights, Restricted Stock and Performance Units or any combination thereof are to be granted hereunder;

(c)	to determine the number of shares of Common Stock to be covered by each Award granted hereunder;

(d)

to determine the terms and conditions of any Award granted hereunder, including, but not limited to, the option price (subject to Section 5(a)), any vesting condition, restriction or limitation (which may be related to the performance of the participant, the Company, any Affiliate or one or more business or functional units thereof) and any vesting acceleration or forfeiture waiver regarding any Award and the shares of Common Stock relating thereto, based on such factors as the Committee shall determine;

(e)

to modify, amend or adjust the terms and conditions of any Award, at any time or from time to time, including but not limited to Performance Goals; provided, however, that the Committee may not adjust upwards the amount payable to a designated Covered Employee with respect to a particular Award upon the satisfaction of applicable Performance Goals or take any other such action to the extent such action or the Committee’s ability to take such action would cause any Award under the Plan to any Covered Employee to fail to qualify as “performance-based compensation” within the meaning of Section 162(m) and the regulations issued thereunder; and

(f)	to determine under what circumstances an Award may be settled in cash or Common Stock under Sec- tion 8(b)(i).

The Committee shall have the authority to adopt, alter and repeal such administrative rules, guidelines and practices governing the Plan as it shall from time to time deem advisable, to construe and interpret the terms and provisions of the Plan and any Award issued under the Plan (and any agreement relating thereto) and to otherwise supervise the administration of the Plan.

The Committee may act only by a majority of its members then in office, except that the members thereof may (i) delegate to an officer of the Company the authority to make decisions pursuant to paragraphs (c), (f), (g), (h) and (i) of Section 5 (provided that no such delegation may be made that would cause Awards or other transactions under the Plan to cease to be exempt from Section 16(b) of the Exchange Act) and (ii) authorize any one or more of their number or any officer of the Company to execute and deliver documents on behalf of the Committee.

Any determination made by the Committee or pursuant to delegated authority pursuant to the provisions of the Plan with respect to any Award shall be made in the sole discretion of the Committee or such delegate at the time of the grant of the Award or, unless in contravention of any express term of the Plan, at any time thereafter.

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All decisions made by the Committee or any appropriately delegated officer pursuant to the provisions of the Plan shall be final and binding on all persons, including the Company and its Affiliates and Plan participants.

Section 3. Common Stock Subject to Plan; Other Limitations.

The total number of shares of Common Stock reserved and available for issuance under the Plan shall be 2,750,000; provided, that not more than 600,000 of such shares shall be issued as Restricted Stock; and provided further that all of such shares may be available for issuance upon exercise of Incentive Stock Options. No participant may be granted Awards covering in excess of 500,000 shares of Common Stock in any one calendar year, and all such Awards may be granted as Stock Options or Stock Appreciation Rights (if any). No participant who is a non-employee director of the Company or an Affiliate may be granted, in any one calendar year, Awards covering in excess of 5,000 shares of Common Stock. Shares subject to an Award under the Plan may be authorized and unissued shares or may be treasury shares. No participant may be granted Performance Units in any one calendar year payable in cash in an amount that would exceed $1,000,000 and no participant who is a non-employee director of the Company or an Affiliate may be granted Performance Units in any one calendar year payable in cash in an amount that would exceed $15,000.

Subject to Section 7(c)(iv), if any shares of Restricted Stock are forfeited for which the participant did not receive any benefits of ownership (as such phrase is construed by the Commission or its staff), or if any Stock Option (and related Stock Appreciation Right, if any) terminates without being exercised, or if any Stock Appreciation Right is exercised for cash, shares subject to such Awards shall again be available for distribution in connection with Awards under the Plan. In the event that (a) any participant delivers shares of Common Stock (i) to pay the exercise price of a Stock Option or any other Award, or (ii) in satisfaction of any tax withholding requirement, or (b) any other payment made or benefit realized under the Plan is satisfied by the transfer or relinquishment of shares of Common Stock, the number of shares of Common Stock available for Awards under the Plan shall be increased by the number of shares of Common Stock so surrendered, paid or relinquished.

In the event of any change in corporate capitalization, such as a stock split or dividend, or a corporate transaction, such as any merger, consolidation, share exchange, separation, including a spin-off, or other distribution of stock or property of the Company, any reorganization (whether or not such reorganization comes within the definition of such term in Section 368 of the Code) or any partial or complete liquidation of the Company, the Committee or Board will make such substitution or adjustments in the number and kind of shares reserved for issuance under the Plan in the aggregate or to any participant, in the number, kind and option price of shares subject to outstanding Stock Options and Stock Appreciation Rights, in the number and kind of shares subject to other outstanding Awards granted under the Plan and/or such other equitable substitution or adjustments as it may determine to be appropriate in its sole discretion; provided, however, that the number of shares subject to any Award shall always be a whole number. Such adjusted option price shall also be used to determine the amount payable by the Company upon the exercise of any Stock Appreciation Right associated with any Stock Option.

Section 4. Eligibility.

Officers and employees of the Company or its Affiliates who are responsible for or contribute to the management, growth and profitability of the business of the Company and its Affiliates and non-employee directors of the Company or an Affiliate are eligible to be granted Awards under the Plan.

Section 5. Stock Options.

The Committee shall determine the non-employee directors, officers and employees to whom and the time or times at which Stock Options shall be granted under the Plan. Stock Options may be granted alone or in addition to other Awards granted under the Plan and may be of two types: Incentive Stock Options and Nonqualified Stock Options. Any Stock Option granted under the Plan shall be in such form as the Committee may from time to time approve.

The Committee shall have the authority to grant any optionee Incentive Stock Options, Nonqualified Stock Options or both types of Stock Options (in each case with or without Stock Appreciation Rights); provided, however, that grants hereunder are subject to the aggregate limits on grants to individual participants set forth in Section 3. To the extent that any Stock Option is not designated as an Incentive Stock Option or, even if so designated, does not qualify as an Incentive Stock Option, it shall constitute a Nonqualified Stock Option.

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Incentive Stock Options may be granted only to employees of the Company and its subsidiaries (within the meaning of Section 424(f) of the Code). In addition, no Stock Option (or Stock Appreciation Right granted in conjunction therewith) may be granted to any non-employee director, officer or employee unless he or she provides direct services on the date of grant to the Company or any corporation or other entity in a chain of corporations or other entities in which each corporation or other entity has a controlling interest in another corporation or other entity in the chain, beginning with the Company and ending with the corporation or other entity for which the non-employee director, officer or employee provides direct services. For this purpose, the term “controlling interest” shall have the same meaning as provided in Treasury Regulations Section 1.414(c)-2(b)(2)(i), provided that the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears therein, and provided further that, where the Committee, based on legitimate business criteria, so determines in its discretion, the term “controlling interest” shall have the same meaning as provided in said regulation except that the language “at least 20 percent” is used instead of “at least 80 percent” each place it appears therein.

Stock Options shall be evidenced by option agreements, the terms and provisions of which may differ. An option agreement shall indicate on its face whether it is intended to be an agreement for an Incentive Stock Option or a Nonqualified Stock Option. The grant of a Stock Option shall occur on the date the Committee by resolution selects an individual to be a participant in any grant of a Stock Option, determines the number of shares of Common Stock to be subject to such Stock Option to be granted to such individual and specifies the terms and provisions of the Stock Option. The Company shall notify a participant of any grant of a Stock Option, and a written option agreement or agreements shall be duly executed and delivered by the Company to the participant. Such agreement or agreements shall become effective upon execution by the Company and the participant.

Anything in the Plan to the contrary notwithstanding, no term of the Plan relating to Incentive Stock Options shall be interpreted, amended or altered nor shall any discretion or authority granted under the Plan be exercised so as to disqualify the Plan under Section 422 of the Code or, without the consent of the optionee affected, to disqualify any Incentive Stock Option under such Section 422.

Stock Options granted under the Plan shall be subject to the following terms and conditions and shall contain such additional terms and conditions as the Committee shall deem desirable:

(a)	Option Price. The option exercise price per share of Common Stock purchasable under a Stock Option shall be determined by the Committee and set forth in the option agreement, and shall not be less than the Fair Market Value of the Common Stock subject to the Stock Option on the date of grant.

(b)	Option Term. The term of each Stock Option shall be fixed by the Committee, but no Stock Option shall be exercisable more than 10 years after the date the Stock Option is granted.

(c)

Exercisability. Except as otherwise provided herein, Stock Options shall be exercisable at such time or times and subject to such terms and conditions as shall be determined by the Committee. If the Committee provides that any Stock Option is exercisable only in installments, the Committee may at any time waive such installment exercise provisions, in whole or in part, based on such factors as the Committee may determine. In addition, the Committee may at any time accelerate the exercisability of any Stock Option.

(d)

Method of Exercise. Subject to the provisions of this Section 5, Stock Options may be exercised, in whole or in part, at any time during the option term by giving written notice of exercise to the Secretary of the Company at the Company’s principal executive office, specifying the number of shares of Common Stock subject to the Stock Option to be purchased.

Such notice shall be accompanied by payment in full of the purchase price by certified or bank check or such other instrument as the Company may accept, or in such other manner as the Committee approves. If approved by the Committee, payment in full or in part may also be made in the form of unrestricted Common Stock already owned by the optionee of the same class as the Common Stock subject to the Stock Option and, in the case of the exercise of a Nonqualified Stock Option, Restricted Stock subject to an Award hereunder which is of the same class as the Common Stock subject to the Stock Option (based, in each case, on the Fair Market Value of the Common Stock on the date the Stock Option is exercised); provided, however, that, in the case of an Incentive Stock Option, the right to make a payment in the form of already owned shares of Common Stock of the same class as the Common Stock subject to the Stock Option may be authorized only at the time the Stock Option is granted.

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If payment of the option exercise price of a Nonqualified Stock Option is made in whole or in part in the form of Restricted Stock, the number of shares of Common Stock to be received upon such exercise equal to the number of shares of Restricted Stock used for payment of the option exercise price shall be subject to the same forfeiture restrictions to which such Restricted Stock was subject, unless otherwise determined by the Committee.

In the discretion of the Committee and to the extent not prohibited by applicable law, payment for any shares subject to a Stock Option may also be made by delivering a properly executed exercise notice to the Company, together with a copy of irrevocable instructions to a broker to deliver promptly to the Company the amount of sale or loan proceeds to pay the purchase price, and, if requested by the Company, the amount of any federal, state, local or foreign withholding taxes. To facilitate the foregoing, the Company may enter into agreements for coordinated procedures with one or more brokerage firms.

No shares of Common Stock shall be issued until full payment therefor has been made. Subject to any forfeiture restrictions that may apply if a Stock Option is exercised using Restricted Stock, an optionee shall have all of the rights of a shareholder of the Company holding the class or series of Common Stock that is subject to such Stock Option (including, if applicable, the right to vote the shares and the right to receive dividends), when the optionee has given written notice of exercise, has paid in full for such shares and, if requested, has given the representation described in Section 13(a).

(e)

Nontransferability of Stock Options. No Stock Option shall be transferable by the optionee other than (i) by will or by the laws of descent and distribution or (ii) in the case of a Nonqualified Stock Option, pursuant to a gift to such optionee’s children, whether directly or indirectly or by means of a trust or partnership or otherwise, or to a charitable organization as described in Code Section 170(c), in either case if expressly permitted under the applicable option agreement. All Stock Options shall be exercisable, during the optionee’s lifetime, only by the optionee or by the guardian or legal representative of the optionee, it being understood that the terms “holder” and “optionee” include the guardian and legal representative of the optionee named in the option agreement and any person to whom an option is transferred by will or the laws of descent and distribution or, in the case of a Nonqualified Stock Option, a gift permitted under the applicable option agreement.

(f)

Termination of Employment By Death. Unless otherwise determined by the Committee, if an optionee incurs a Termination of Employment by reason of death, any Stock Option held by such optionee shall immediately become exercisable and may thereafter be exercised by the holder for a period of three years (or such shorter period as the Committee may specify in the option agreement) from the date of such death or until the expiration of the stated term of such Stock Option, whichever period is the shorter.

(g)

Termination of Employment By Reason of Disability. Unless otherwise determined by the Committee, if an optionee incurs a Termination of Employment by reason of Disability, any Stock Option held by such optionee shall immediately become exercisable and may thereafter be exercised by the optionee for a period of three years (or such shorter period as the Committee may specify in the option agreement) from the date of such Termination of Employment or until the expiration of the stated term of such Stock Option, whichever period is the shorter; provided, however, that if the optionee dies within such three-year period (or such shorter period), any unexercised Stock Option held by such optionee shall, notwithstanding the expiration of such three-year (or such shorter) period, continue to be exercisable for a period of 12 months from the date of such death or until the expiration of the stated term of such Stock Option, whichever period is the shorter. In the event of Termination of Employment by reason of Disability, if an Incentive Stock Option is exercised after the expiration of the exercise periods that apply for purposes of Section 422 of the Code, such Stock Option will thereafter be treated as a Nonqualified Stock Option.

(h)

Termination of Employment By Reason of Retirement. Unless otherwise determined by the Committee, if an optionee incurs a Termination of Employment by reason of Retirement, any Stock Option held by such optionee shall immediately become exercisable and may thereafter be exercised by the optionee for a period of three years (or such shorter period as the Committee may specify in the option agreement) from the date of such Termination of Employment or until the expiration of the stated term of such Stock Option, whichever period is the shorter; provided, however, that if the optionee dies within such three-year (or such shorter) period any unexercised Stock Option held by such optionee shall, not withstanding the expiration of such three-year (or such shorter) period, continue to be exercisable for a period of 12 months from the

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date of such death or until the expiration of the stated term of such Stock Option, whichever period is the shorter. In the event of Termination of Employment by reason of Retirement, if an Incentive Stock Option is exercised after the expiration of the exercise periods that apply for purposes of Section 422 of the Code, such Stock Option will thereafter be treated as a Nonqualified Stock Option.

(i)

Other Termination of Employment. Unless otherwise determined by the Committee, if an optionee incurs a Termination of Employment for any reason other than death, Disability or Retirement, any Stock Option held by such optionee, whether then exercisable or not, shall thereupon terminate, except that if such Termination of Employment is involuntary, such Stock Option, to the extent then exercisable, or on such accelerated basis as the Committee may determine, may be exercised for the lesser of three months from the date of such Termination of Employment or the balance of such Stock Option’s stated term; provided, however, that if the optionee dies within such three-month period, any unexercised Stock Option then held by such optionee shall, notwithstanding the expiration of such three-month period, continue to be exercisable to the extent to which it was exercisable at the time of death for a period of 12 months from the date of such death or until the expiration of the stated term of such Stock Option, whichever period is the shorter. Notwithstanding the foregoing, if an optionee incurs a Termination of Employment at or after a Change of Control (as defined in Section 9(b)), other than by reason of death, Disability or Retirement, any Stock Option held by such optionee shall be exercisable for the lesser of (1) six months and one day from the date of such Termination of Employment, or (2) the balance of such Stock Option’s stated term. In the event of Termination of Employment, if an Incentive Stock Option is exercised after the expiration of the exercise periods that apply for purposes of Section 422 of the Code, such Stock Option will thereafter be treated as a Nonqualified Stock Option.

(j)

Change of Control Cash-Out. Notwithstanding any other provision of the Plan, during the 60-day period from and after a Change of Control (the “Exercise Period”), unless the Committee shall determine otherwise at the time of grant, an optionee shall have the right, whether or not the Stock Option is fully exercisable and in lieu of the payment of the exercise price for the shares of Common Stock being purchased under the Stock Option and by giving notice to the Company, to elect (within the Exercise Period) to surrender all or part of the Stock Option to the Company and to receive cash, within 30 days of such notice, in an amount equal to the amount by which the Fair Market Value per share of Common Stock on the date of such election shall exceed the exercise price per share of Common Stock under the Stock Option (the “Spread”) multiplied by the number of shares of Common Stock granted under the Stock Option as to which the right granted under this Section 5(j) shall have been exercised.

Section 6. Stock Appreciation Rights.

(a)

Grant and Exercise. Stock Appreciation Rights may be granted by the Committee, in conjunction with all or part of any Stock Option granted under the Plan, for a fixed number of shares of Common Stock. In the case of a Nonqualified Stock Option, such rights may be granted either at or after the time of grant of such Stock Option. In the case of an Incentive Stock Option, such rights may be granted only at the time of grant of such Stock Option. A Stock Appreciation Right shall terminate and no longer be exercisable upon the termination or exercise of the related Stock Option.

A Stock Appreciation Right may be exercised by an optionee in accordance with Section 6(b) by surrendering the applicable portion of the related Stock Option in accordance with procedures established by the Committee. Upon such exercise and surrender, the optionee shall be entitled to receive an amount determined in the manner prescribed in Section 6(b). Stock Options which have been so surrendered shall no longer be exercisable to the extent the related Stock Appreciation Rights have been exercised.

(b)	Terms and Conditions. Stock Appreciation Rights shall be granted pursuant to a written agreement which shall contain such terms and conditions as shall be determined by the Committee, including the following:

(i)

Stock Appreciation Rights shall be exercisable only at such time or times and to the extent that the Stock Options to which they relate are exercisable in accordance with the provisions of Section 5 and this Section 6.

(ii)

Upon the exercise of a Stock Appreciation Right, an optionee shall be entitled to receive an amount in cash, shares of Common Stock or both equal in value to the excess of the Fair Market Value on the date of exercise of one share of Common Stock over the option price per share specified in the related

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Stock Option (or, if the Stock Appreciation Right was granted after the time of grant of the related Stock Option, over the strike price for the Stock Appreciation Right as determined by the Committee and set forth in the Stock Appreciation Right agreement, which strike price per share shall not be less than the Fair Market Value per share of Common Stock on the date of grant of the Stock Appreciation Right) multiplied by the number of shares in respect of which the Stock Appreciation Right shall have been exercised, with the Committee having the right to determine the form of payment.

(iii)

Stock Appreciation Rights shall be transferable only to permitted transferees of the underlying Stock Option in accordance with Section 5(e).

(iv)

Upon the exercise of a Stock Appreciation Right, the Stock Option or part thereof to which such Stock Appreciation Right is related shall be deemed to have been exercised for the purpose of the limitation set forth in Section 3 on the number of shares of Common Stock to be issued under the Plan, but only to the extent of the number of shares as to which the Stock Appreciation Right is exercised at the time of exercise.

Section 7. Restricted Stock.

(a)

Administration. Shares of Restricted Stock may be awarded either alone or in addition to other Awards granted under the Plan. The Committee shall determine the non-employee directors, officers and employees to whom and the time or times at which grants of Restricted Stock will be awarded, the number of shares to be awarded to any participant (subject to the aggregate limits on grants to individual participants set forth in Section 3), the conditions for vesting, the time or times within which such Awards may be subject to forfeiture and any other terms and conditions of the Awards, in addition to those contained in Section 7(c).

The Committee shall in the case of Covered Employees, and may in the case of other participants, condition the vesting of Restricted Stock upon the attainment of Performance Goals established before or at the time of grant and, in each instance, may establish the various levels of achievement of Performance Goals at which a portion or all of such Restricted Stock vests. In the case of Covered Employees, prior to the vesting of any Restricted Stock, the Committee shall certify in writing that the applicable Performance Goals and any other material terms have been satisfied. The Committee may, in addition to requiring satisfaction of any applicable Performance Goals, also condition vesting upon the continued service of the participant. The provisions of Restricted Stock Awards (including the applicable Performance Goals) need not be the same with respect to each recipient.

(b)

Awards and Certificates. Shares of Restricted Stock shall be evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of one or more stock certificates. Any certificate issued in respect of shares of Restricted Stock shall be registered in the name of such participant and shall bear an appropriate legend referring to the terms, conditions, and restrictions applicable to such Award, substantially in the following form:

“The transferability of this certificate and the shares of stock represented hereby are subject to the terms and conditions (including forfeiture) of the OGE Energy Corp. 2008 Stock Incentive Plan and a Restricted Stock Agreement. Copies of such Plan and Agreement are on file at the offices of OGE Energy Corp. at 321 North Harvey, Oklahoma City, Oklahoma 73101-0321.”

The Committee may require that any certificates evidencing such shares be held in custody by the Company until the restrictions thereon shall have lapsed and that, as a condition of any Award of Restricted Stock, the participant shall have delivered a stock power, endorsed in blank, relating to the Common Stock covered by such Award.

(c)	Terms and Conditions. Shares of Restricted Stock shall be subject to the following terms and conditions:

(i)

Subject to the provisions of the Plan (including Section 5(d)) and the Restricted Stock Agreement referred to in Section 7(c)(vi), during the period, if any, set by the Committee, commencing with the date of such Award for which such participant’s continued service is required (the “Restriction Period”), and until the later of (i) the expiration of the Restriction Period and (ii) the date the applicable Performance Goals (if any) are satisfied, the participant shall not be permitted to sell, as-

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sign, transfer, pledge or otherwise encumber shares of Restricted Stock. Within these limits, the Committee may provide for the lapse of restrictions based upon period of service in installments or otherwise and may accelerate or waive, in whole or in part, restrictions based upon period of service or upon performance; provided, however, that in the case of Restricted Stock with respect to which a participant is a Covered Employee, any applicable Performance Goals have been satisfied.

(ii)

Except as provided in this paragraph (ii) and Section 7(c)(i) and the Restricted Stock Agreement, the participant shall have, with respect to the shares of Restricted Stock, all of the rights of a shareholder of the Company holding the class or series of Common Stock that is the subject of the Restricted Stock, including, if applicable, the right to vote the shares and the right to receive any cash dividends. If so determined by the Committee in the applicable Restricted Stock Agreement and subject to Section 13(f) of the Plan (1) cash dividends on the class or series of Common Stock that is the subject of the Restricted Stock Award shall be automatically reinvested in additional Restricted Stock, held subject to the vesting of the underlying Restricted Stock, or held subject to meeting Performance Goals applicable only to dividends, and (2) dividends payable in Common Stock shall be paid in the form of Restricted Stock of the same class as the Common Stock with which such dividend was paid, held subject to the vesting of the underlying Restricted Stock, or held subject to meeting Performance Goals applicable only to dividends.

(iii)

Except to the extent otherwise provided in the applicable Restricted Stock Agreement, any applicable employment agreement and Sections 7(c)(i), 7(c)(iv) and 9(a)(ii), upon a participant’s Termination of Employment for any reason during the Restriction Period or before the applicable Performance Goals are satisfied, all shares still subject to restriction shall be forfeited by the participant.

(iv)

Except to the extent otherwise provided in Section 9(a)(ii), in the event that a participant incurs a Termination of Employment due to Retirement or involuntary termination, the Committee shall have the discretion to waive in whole or in part any or all remaining restrictions (other than, in the case of Restricted Stock with respect to which a participant is a Covered Employee, satisfaction of the applicable Performance Goals unless the participant’s Termination of Employment is due to death or Disability) with respect to any or all of such participant’s shares of Restricted Stock.

(v)

If and when the applicable Performance Goals are satisfied for any shares of Restricted Stock and the Restriction Period expires without a prior forfeiture of such shares of Restricted Stock, unlegended certificates for such shares shall be delivered to the participant upon surrender of the legended certificates.

(vi)

Each Award shall be confirmed by, and be subject to the terms of, a written Restricted Stock Agreement.

Section 8. Performance Units.

(a)

Administration. Performance Units may be awarded either alone or in addition to other Awards granted under the Plan. Performance Units may be denominated in shares of Common Stock or cash, or may represent the right to receive dividend equivalents with respect to shares of Common Stock, as the Committee shall determine. The Committee shall determine the non-employee directors, officers and employees to whom and the time or times at which Performance Units shall be awarded, the form and number of Performance Units to be awarded to any participant (subject to the aggregate limits on grants to individual participants set forth in Section 3), the duration of the Award Cycle and any other terms and conditions of the Award, in addition to those contained in Section 8(b).

The Committee shall condition the settlement of Performance Units upon the attainment of Performance Goals, which shall be established before or at the time of grant. The provisions of such Awards (including the applicable Performance Goals) need not be the same with respect to each recipient.

(b)	Terms and Conditions. Performance Unit Awards shall be subject to the following terms and conditions:

(i)

Subject to the provisions of the Plan and the Performance Unit Agreement referred to in Section 8(b) (iv), Performance Units may not be sold, assigned, transferred, pledged or otherwise encumbered during the Award Cycle. After the expiration of the Award Cycle, the Committee shall evaluate actual performance in light of the Performance Goals for such Award, shall certify in writing the extent to which such Performance Goals and other material terms have been satisfied and shall determine the number of Performance

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Units granted to the participant which have been earned and the Committee may then elect to deliver cash, shares of Common Stock, or a combination thereof, in settlement of the earned Performance Units, in accordance with the terms thereof. Settlement of earned Performance Units, if any, for an Award Cycle shall in no event be made later than the 15th day of the third month after the end of such Award Cycle.

(ii)

Except to the extent otherwise provided in the applicable Performance Unit Agreement and Sections 8(b)(iii) and 9(a)(iii), upon a participant’s Termination of Employment for any reason during the Award Cycle or before the applicable Performance Goals are satisfied, the rights to the shares or cash still covered by the Performance Unit Award shall be forfeited by the participant.

(iii)

Except to the extent otherwise provided in the applicable Performance Unit Agreement and Section 9(a)(iii), in the event that a participant incurs a Termination of Employment due to death, Disability or Retirement, such participant shall receive a prorated payment based on such participant’s number of full months of service during the Award Cycle, further adjusted based on the achievement of the Performance Goals during the entire Award Cycle, as certified by the Committee. Payment shall be made at the time payments are made to participants who did not terminate service during the Award Cycle.

(iv)

Each Award shall be confirmed by, and be subject to the terms of, a written Performance Unit Agreement.

Section 9. Change of Control Provisions.

(a)	Impact of Event. Notwithstanding any other provision of the Plan to the contrary, in the event of a Change of Control:

(i)

Any Stock Options and Stock Appreciation Rights outstanding as of the date such Change of Control is determined to have occurred and not then exercisable and vested shall become fully exercisable and vested to the full extent of the original grant.

(ii)

The restrictions applicable to any Restricted Stock shall lapse, and such Restricted Stock shall become free of all restrictions and become fully vested and transferable to the full extent of the original grant.

(iii)

All Performance Units shall be considered to be earned and payable in full in an amount that will be equal to the number of Performance Units that would have been payable had the Performance Goals been met at a level that would result in a 100% payout of the Performance Units awarded, and any restrictions shall lapse and such Performance Units shall be settled in cash as promptly as is practicable but in no event later than the 15th day of the third month after the occurrence of the Change of Control.

(b)	Definition of Change of Control. For purposes of the Plan, a “Change of Control” shall mean the happening of any of the following events:

(i)

An acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (1) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); excluding, however, the following: (1) any acquisition directly from the Company, (2) any acquisition by the Company, (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation or other Person controlled by the Company or (4) any acquisition by any corporation or other Person pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (iii) of this Section 9(b); or

(ii)

A change in the composition of the Board such that the individuals who, as of January 1, 2008, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, for purposes of this Section 9(b), that any individual who becomes a member of the Board subsequent to January 1, 2008, whose election, or nomination for election by the Company’s shareowners, was approved by a vote of at least a majority of those individuals then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board; but, provided further, that any such individual whose initial assumption of office

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occurs as a result of either an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board shall not be so considered as a member of the Incumbent Board; or

(iii)

Consummation of a reorganization, merger, share exchange or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), excluding, however, such a Business Combination pursuant to which (1) all or substantially all of the individuals and entities who are the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the outstanding shares of common stock or equity interests and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors or other controlling persons as the case may be, of the corporation or other Person resulting from such Business Combination (including, without limitation, a corporation or other Person which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (other than the corporation or other Person resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation or other Person resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the outstanding shares of common stock or equity interests of the corporation or other Person resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed with respect to the Company prior to the Business Combination and (3) at least a majority of the members of the board of directors or other governing body of the corporation or other Person resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or the action of the Board, providing for such Business Combination; or

(iv)

The approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

Section 10. Loans.

The Company shall not make any loan to a participant in connection with the exercise of Stock Options under the Plan or otherwise in connection with any other Awards under the Plan.

Section11. Term, Amendment and Termination.

The Plan will terminate 10 years after the effective date of the Plan. Under the Plan, Awards outstanding as of such date shall not be affected or impaired by the termination of the Plan.

The Board may amend, alter, or discontinue the Plan, but no amendment, alteration or discontinuation shall be made which would (i) impair the rights of an optionee under a Stock Option or a recipient of a Stock Appreciation Right, Restricted Stock Award or Performance Unit Award theretofore granted without the optionee’s or recipient’s consent, except such an amendment made to cause the Plan to qualify or continue to qualify for the exemption provided by Rule 16b-3 or to comply with or qualify for an exemption from Code Section 409A and the regulations promulgated thereunder, or (ii) disqualify the Plan from the exemption provided by Rule 16b-3. In addition, no such amendment shall be made without the approval of the Company’s shareholders to the extent such approval is required by law or agreement.

The Committee may amend the terms of any Stock Option or other Award theretofore granted, prospectively or retroactively, except that: (i) no such amendment shall impair the rights of any holder without the holder’s written consent except such an amendment made to cause the Plan or Award to qualify for the exemption provided by Rule 16b-3 or to comply with or qualify for an exemption from Code Section 409A and the regulations promulgated thereunder and (ii) no such amendment shall lower the option exercise price of a Stock Option other than as permitted by Section 3 in connection with a change in corporate capitalization or other transaction described in Section 3.

Subject to the above provisions, the Board shall have authority to amend the Plan to take into account changes in law and tax and accounting rules, as well as other developments and to grant Awards which qualify for beneficial treatment under such rules without shareholder approval.

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Section 12. Unfunded Status of Plan.

It is presently intended that the Plan constitute an “unfunded” plan for incentive and deferred compensation. The Committee may authorize the creation of trusts or other arrangements to meet the obligations created under the Plan to deliver Common Stock or make payments; provided, however, that, unless the Committee otherwise determines, the existence of such trusts or other arrangements is consistent with the “unfunded” status of the Plan.

Section 13. General Provisions.

(a)

The Committee may require each person purchasing or receiving shares pursuant to an Award to represent to and agree with the Company in writing that such person is acquiring the shares without a view to the distribution thereof. The certificates for such shares may include any legend which the Committee deems appropriate to reflect any restrictions on transfer.

Notwithstanding any other provision of the Plan or agreements made pursuant thereto, the Company shall not be required to issue or deliver any certificate or certificates for shares of Common Stock under the Plan prior to fulfillment of all of the following conditions:

(i)

The listing or approval for listing upon notice of issuance, of such shares on the New York Stock Exchange, Inc., or such other securities exchange as may at the time be the principal market for the Common Stock;

(ii)

Any registration or other qualification of such shares of the Company under any state or Federal law or regulation, or the maintaining in effect of any such registration or other qualification which the Committee shall, in its absolute discretion upon the advice of counsel, deem necessary or advisable; and

(iii)

The obtaining of any other consent, approval, or permit from any state or Federal governmental agency which the Committee shall, in its absolute discretion after receiving the advice of counsel, determine to be necessary or advisable.

(b)	Nothing contained in the Plan shall prevent the Company or any Affiliate from adopting other or additional compensation arrangements for its employees.

(c)	The adoption of the Plan shall not confer upon any employee any right to continued employment nor shall it interfere in any way with the right of the Company or any Affiliate to terminate the employment of any employee at any time.

(d)

No later than the date as of which an amount first becomes includible in the gross income of the participant for Federal income tax purposes with respect to any Award under the Plan, the participant shall pay to the Company, or make arrangements satisfactory to the Company regarding the payment of, any Federal, state, local or foreign taxes of any kind required by law to be withheld with respect to such amount. Unless otherwise determined by the Company, withholding obligations may be settled with Common Stock, including Common Stock that is part of the Award that gives rise to the withholding requirement. The obligations of the Company under the Plan shall be conditional on such payment or arrangements, and the Company and its Affiliates shall, to the extent permitted by law, have the right to deduct any such taxes from any payment otherwise due to the participant. The Committee may establish such procedures as it deems appropriate, including the making of irrevocable elections, for the settlement of withholding obligations with Common Stock.

(e)	The Plan and all Awards made and actions taken thereunder shall be governed by and construed in accordance with the laws of the State of Oklahoma, without reference to principles of conflict of laws.

(f)	The reinvestment of dividends in additional Restricted Stock at the time of any dividend payment shall only be permissible if sufficient shares of Common Stock are available under Section 3 for such reinvestment (taking into account then outstanding Stock Options and other Awards).

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(g)	The Committee shall establish such procedures as it deems appropriate for a participant to designate a beneficiary to whom any amounts payable in the event of the participant’s death are to be paid or by whom any rights of the participant, after the participant’s death, may be exercised.

(h)

In the case of a grant of an Award to any employee or non-employee director of an Affiliate, the Company may, if the Committee so directs, and shall in the case of an Award of Restricted Stock to any employee or non-employee director of an Affiliate which would not be considered as a single employer with the Company under Code Sections 414(b) and (c), issue or transfer the shares of Common Stock, if any, covered by the Award to the Affiliate, for such lawful consideration as the Committee may specify, upon the condition or understanding that the Affiliate will transfer the shares of Common Stock to the employee or non-employee director in accordance with the terms of the Award specified by the Committee pursuant to the provisions of the Plan.

(i)

The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization or otherwise) to all or substantially all of the business and/or assets of the Company expressly to assume and agree to perform this Plan in the same manner and to the same extent the Company would be required to perform if no such succession had taken place. This Plan shall be binding upon and inure to the benefit of the Company and any successor to the Company, including without limitation any persons acquiring directly or indirectly all or substantially all of the business and/or assets of the Company whether by purchase, merger, consolidation, reorganization or otherwise (and such successor shall thereafter be deemed the “Company” for the purposes of this Plan), and the heirs, executors and administrators of each Participant.

(j)	Awards under the Plan are not intended to provide for the deferral of compensation within the meaning of Section 409A of the Code and the regulations promulgated thereunder. The Plan shall be interpreted, construed and administered in a manner consistent with this intent.

(k)

The provisions of this Plan are not intended, and should not be construed to be legal, business or tax advice. The Company, Participants and any other party having any interest herein are hereby informed that the U.S. federal tax advice contained in this document (if any) is not intended or written to be used, and cannot be used, for the purpose of (i) avoiding penalties under the Code or (ii) promoting, marketing or recommending to any party any transaction or matter addressed herein.

Section 14. Effective Date of Plan.

The Plan shall be effective as of June 30, 2008, subject to approval of the Plan by the shareowners of the Company at its 2008 annual meeting by the affirmative vote of a majority of the votes entitled to be cast by the holders of the shares of common stock of the Company represented at the meeting and entitled to vote thereon.

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Annex B

OGE ENERGY CORP.

2008 ANNUAL INCENTIVE COMPENSATION PLAN

I.	PURPOSE AND EFFECTIVE TIME OF THE PLAN

The purpose of the 2008 Annual Incentive Compensation Plan (the “Plan”) is to maximize the efficiency and effectiveness of the operations of OGE Energy Corp. and its subsidiaries by providing incentive compensation opportunities to certain key executives and managers responsible for operational effectiveness. The Plan is intended to encourage and reward the achievement of certain results critical to meeting the Company’s operational goals. It is also designed to assist in the attraction and retention of quality employees, to link further the financial interest and objectives of employees with those of the Company and to foster accountability and teamwork throughout the Company.

This Plan is designed to provide incentive compensation opportunities; awards made under this Plan are in addition to base salary adjustments given to maintain market competitive salary levels.

Payments pursuant to Article VI of the Plan are intended to qualify under the performance-based compensation exemption of Section 162(m)(4)(C) of the Internal Revenue Code of 1986, as amended.

The Plan shall be effective as of June 30, 2008, subject to approval of the Plan by the shareowners of OGE Energy Corp. at its 2008 annual meeting by the affirmative vote of a majority of the shares of common stock of OGE Energy Corp. present in person or represented by proxy at the meeting and entitled to vote.

II.

DEFINITIONS

When used in the Plan, the following words and phrases shall have the following meanings:

2.1

“Affiliate” means in respect of Energy Corp. or other Company, any corporation, partnership, joint venture, trust, association or other business enterprise which is a member of the same controlled group of corporations, trades or businesses as Energy Corp. or such other Company, as the case may be, within the meaning of Code Section 414(b) or (c); provided, however, that, except for purposes of the term “Affiliate” when used in Section 10.3 below, in applying Code Section 1563(a)(1), (2), and (3) in determining a controlled group of corporations under Code Section 414(b), the language “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Code Section 1563(a)(1), (2), and (3), and in applying Treasury Reg. § 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code Section 414(c), “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Treasury Reg. § 1.414(c)-2.

2.2	“Base Salary” means the actual base salary paid to a Participant during the Plan Year as shown in the personnel records of the Company (annualized in the event the Participant was not employed for the whole of such Plan Year).

2.3	“Board ” means the Board of Directors of Energy Corp.

2.4	“Change of Control” shall mean the happening of any of the following events:

(i)

An acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (1) the then outstanding shares of common stock of Energy Corp. (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of Energy Corp. entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); excluding, however, the following: (1) any acquisition directly from Energy Corp., (2) any acquisition by Energy Corp., (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Energy Corp. or any corporation or other Person controlled by Energy Corp. or (4) any acquisition by any corporation or other Person pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (iii) below; or

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(ii)

A change in the composition of the Board such that the individuals who, as of January 1, 2008, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual who becomes a member of the Board subsequent to January 1, 2008, whose election, or nomination for election by Energy Corp.’s shareowners, was approved by a vote of at least a majority of those individuals then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board; but, provided further, that any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board shall not be so considered as a member of the Incumbent Board; or

(iii)

Consummation of a reorganization, merger, share exchange or consolidation or sale or other disposition of all or substantially all of the assets of Energy Corp. (a “Business Combination”), excluding, however, such a Business Combination pursuant to which (1) all or substantially all of the individuals and entities who are the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the outstanding shares of common stock or equity interests and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors or other controlling persons, as the case may be, of the corporation or other Person resulting from such Business Combination (including, without limitation, a corporation or other Person which as a result of such transaction owns Energy Corp. or all or substantially all of Energy Corp.’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (other than the corporation or other Person resulting from such Business Combination or any employee benefit plan (or related trust) of Energy Corp. or such corporation or other Person resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the outstanding shares of common stock or equity interests of the corporation or other Person resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation or other Person except to the extent that such ownership existed with respect to Energy Corp. prior to the Business Combination and (3) at least a majority of the members of the board of directors or other governing body of the corporation or other Person resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or the action of the Board, providing for such Business Combination; or

(iv)

The approval by the shareowners of Energy Corp. of a complete liquidation or dissolution of Energy Corp.

2.5	“Code ” means the Internal Revenue Code of 1986, as amended.

2.6

“Committee ” means the Compensation Committee of the Board or any other committee of the Board designated by resolution of the Board to perform certain administrative functions under the Plan provided that, to the extent awards under the Plan are intended to be exempt from Section 162(m) of the Code, such Committee shall be comprised of two or more persons, each of whom shall qualify as an “outside director” for purposes of Section 162(m)(4) of the Code.

2.7	“Company ” means Energy Corp., its subsidiary, Oklahoma Gas and Electric Company, and any directly or indirectly-owned domestic subsidiary or division of these entities, as designated by the Committee for participation in the Plan.

2.8	“Company Performance Goals” shall have the meaning ascribed to it by Section 6.2 hereof.

2.9

“Covered Employee” means, for any Plan Year, a Participant designated by the Committee prior to the grant of a Target Company Award for such Plan Year who is or may be a “covered employee” within the meaning of Section 162(m)(3) of the Code for the Plan Year in which such award would be payable and for whom the Committee intends amounts payable with respect to such award to qualify under the performance-based compensation exemption of Section 162(m)(4)(C) of the Code.

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2.10	“Earned Award” means the Earned Individual Award, if any, and the Earned Company Award, if any, for a Participant for the applicable Plan Year.

2.11	“Earned Company Award” means the actual award earned under a Participant’s Target Company Award during a Plan Year as determined by the Committee after the end of the Plan Year (pursuant to Section 6.3 hereof).

2.12	“Earned Individual Award” means the actual award earned under a Participant’s Target Individual Award during a Plan Year as determined by the Committee after the end of the Plan Year (pursuant to Section 5.4 hereof).

2.13	“Energy Corp.” shall mean OGE Energy Corp. and its successors and assigns.

2.14

“Participant ” means any officer, executive or other key employee of the Company who has been selected by the Committee to be eligible to receive an award under the Plan as provided in Article IV. Members of the Board who are not employed on a full-time basis by the Company are not eligible to receive awards under the Plan.

2.15	“Performance Matrix” means the chart or charts or other schedules approved by the Committee that are used to determine the percentage of each Participant’s Target Company Award which the Participant will actually receive as a result of the attainment of Company Performance Goals.

2.16	“Plan ” means this 2008 Annual Incentive Compensation Plan, as it may be amended from time to time.

2.17	“Plan Year” means a fiscal year beginning January 1 and ending December 31.

2.18

“Separation from Service” means, in respect of a Participant, the Participant’s “separation from service” (as such phrase is defined in Code Section 409A and the regulations promulgated thereunder) with the Participant’s employing Company and its Affiliates because of death, retirement or termination of employment for any other reason; provided, however, that no Separation of Service shall be deemed to occur for purposes of the Plan while the Participant continues to perform services for such Company or its Affiliates in a capacity as an employee or as an independent contractor at a level that is more than 20% of the average level of bona fide services performed (whether as an employee or otherwise) by the Participant during the immediately preceding 36-month period (or, if employed less than 36 months, such lesser period).

2.19	“Target Company Award” means an award established pursuant to Article VI hereof. Such Target Company Award shall be expressed as a percentage of the Participant’s Base Salary.

2.20	“Target Individual Award” means an award established pursuant to Article V hereof. Such Target Individual Award shall be expressed as a percentage of the Participant’s Base Salary.

III.

ADMINISTRATION OF THE PLAN

The Plan shall be administered by the Committee to the extent provided herein. Subject to the provisions of the Plan, the Board shall have exclusive authority to amend, modify, suspend or terminate the Plan at any time.

IV.

ELIGIBILITY AND PARTICIPATION

4.1

Eligibility. Eligibility for participation in the Plan shall be limited to those officers, executives or other key employees of the Company who are nominated for participation by the Chief Executive Officer of Energy Corp. (the “Chief Executive Officer”) and then selected by the Committee to participate in the Plan.

4.2

Participation. Participation in the Plan shall be determined annually based upon nomination by the Chief Executive Officer and selection by the Committee. Specific criteria for participation shall be determined by the Committee prior to the beginning of each Plan Year. Persons selected for participation shall be notified in writing of their selection, and of their individual performance goals and Company Performance Goals and related Target Individual Awards and Target Company Awards, as soon after approval as is practicable.

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4.3

Partial Plan Year Participation. Subject to Article VI herein, the Committee may, upon recommendation of the Chief Executive Officer, allow an individual who becomes eligible after the beginning of a Plan Year to participate in the Plan for that period. In such case, the Participant’s Earned Award normally shall be prorated based on the number of full months of participation during such Plan Year. However, subject to Section 5.1 and Article VI herein, the Chief Executive Officer, subject to Committee approval, may authorize an unreduced Earned Award.

4.4

Termination of Approval. In its sole discretion, the Committee may withdraw its approval for participation in the Plan with respect to a Plan Year for a Participant at any time during such Plan Year; provided, however, that such withdrawal must occur before the end of such Plan Year and provided further that, in the event a Change of Control occurs during a Plan Year, the Committee may not thereafter withdraw its approval for a Participant during such Plan Year. In the event of such withdrawal, the employee concerned shall cease to be a Participant as of the date designated by the Committee, and the employee shall not be entitled to any part of an Earned Award for the Plan Year in which such withdrawal occurs. Such employee shall be notified of such withdrawal in writing as soon as practicable following such action.

V.	INDIVIDUAL AWARDS

5.1

Award Opportunities. At the beginning of each Plan Year, the Committee shall establish Target Individual Award levels for each Participant who is to be granted an opportunity to achieve an Earned Individual Award. The established levels may vary in relation to the responsibility level of the Participant. In the event a Participant changes job levels during the Plan Year, the Target Individual Award may be adjusted at the discretion of the Committee to reflect the amount of time at each job level. Notwithstanding any provision in this Plan to the contrary, for any Plan Year (i) Target Individual Awards and Earned Individual Awards shall not be granted to Covered Employees, and (ii) Target Individual Awards shall not be dependent in any manner on, and shall be established independently of and in addition to, the establishment of any Target Company Awards or the payout of any Earned Company Awards pursuant to Article VI herein.

5.2

Individual Performance Goals. At the beginning of each Plan Year, the Chief Executive Officer shall recommend individual performance goals (which may be based in whole or in part on one or more performance measures relating to Energy Corp. and/or any of its subsidiaries and/or one or more business or functional units thereof) for each Participant who is granted a Target Individual Award. The Committee shall consider and approve or modify the recommendations as appropriate. The level of achievement of the Participant’s individual performance goals at the end of the Plan Year, as determined pursuant to Section 5.4 below, will determine such Participant’s Earned Individual Award, which may range from 0% to 175% of such Participant’s Target Individual Award.

5.3

Adjustment of Individual Performance Goals. The Chief Executive Officer shall have the right to adjust the individual performance goals (either up or down) during the Plan Year if he determines that external changes or other unanticipated conditions have materially affected the fairness of the goals and unduly influenced the ability to meet them; provided, however, that no such adjustment to the Chief Executive Officer’s individual performance goals shall be made unless approved by the Committee; and provided further that no adjustment of such individual performance goals for any Participant shall be made based upon the failure, or the expected failure, to attain or exceed the Company Performance Goals for any Target Company Award granted to such Participant under Article VI herein and provided further that no adjustment shall be made of such individual performance goals for a Plan Year in which a Change of Control occurs.

5.4

Earned Individual Award Determination. After the end of each Plan Year, the Chief Executive Officer shall review the level of achievement of the individual performance goals of each Participant who received a Target Individual Award. Based on the Chief Executive Officer’s determination as to the level of achievement of a Participant’s individual performance goals, the Chief Executive Officer shall make a recommendation to the Committee as to the Earned Individual Award to be received by such Participant. The payment of all Earned Individual Awards is subject to approval by the Committee. The payment of an Earned Individual Award to a Participant shall not be contingent in any manner upon the attainment of, or failure to attain, the Company Performance Goals for the Target Company Awards granted to such Participant under Article VI.

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5.5

Maximum Payable/Aggregate Award Cap. The maximum amount payable to a Participant pursuant to this Article V for any Plan Year shall be $350,000. The Committee also may establish guidelines governing the maximum Earned Individual Awards that may be earned by all Participants in the aggregate, in each Plan Year. These guidelines may be expressed as a percentage of a financial measure, or such other measure as the Committee shall from time to time determine.

VI.

COMPANY AWARDS

In addition to any Target Individual Awards granted under Article V, Target Company Awards based solely on performance of Energy Corp., one or more of its subsidiaries or one or more business or functional units thereof may be established under this Article VI for Participants. Earned Company Awards are intended to satisfy the performance-based compensation exemption under Code Section 162(m)(4)(C) and the related regulations and shall thus be subject to the requirements set forth in this Article VI.

6.1

Award Opportunities. On or before the 90th day of each Plan Year and in any event before 25% or more of the Plan Year has elapsed, the Committee shall establish in writing for each Participant for whom a Target Company Award is to be granted under this Article VI, the Target Company Award and specific objective performance goals for the Plan Year, which goals shall meet the requirements of Section 6.2 herein (such goals are hereinafter referred to as “Company Performance Goals”). The extent, if any, to which an Earned Company Award will be payable to a Participant will be based solely upon the degree of achievement of such preestablished Company Performance Goals over the specified Plan Year; provided, however, that, unless and until a Change of Control occurs, the Committee may, in its sole discretion, reduce or eliminate the amount which would otherwise be payable with respect to a Plan Year. Payment of an Earned Company Award to a Participant shall consist of a cash award from the Company to be based upon a percentage (which may exceed 100%) of the Participant’s Target Company Award.

6.2

Company Performance Goals. The Company Performance Goals established by the Committee pursuant to Section 6.1 will be based on one or more of the following relating to Energy Corp., one or more of its subsidiaries, or one or more business or functional units thereof: total shareholder return; return on equity; return on capital; earnings per share; market share; stock price; sales; costs; net operating income; net income; return on assets; earnings before income taxes, depreciation and amortization; return on total assets employed; capital expenditures; earnings before income taxes; economic value added; cash flow; cash available for distribution; retained earnings; results of customer satisfaction surveys; aggregate product price and other product price measures; safety record; service reliability; demand-side management (including conservation and load management); operating and/or maintenance cost management (including operation and maintenance expenses per Kwh); and energy production availability performance measures. At the time of establishing a Company Performance Goal, the Committee shall specify the manner in which the Company Performance Goal shall be calculated. In so doing, the Committee may exclude the impact of certain specified events from the calculation of the Company Performance Goal. For example, if the Company Performance Goal were earnings per share, the Committee could, at the time this Company Performance Goal was established, specify that earnings per share are to be calculated without regard to any subsequent change in accounting standards required by the Financial Accounting Standards Board. Company Performance Goals also may be based on the attainment of specified levels of performance of Energy Corp., and/or any of its subsidiaries and/or one or more business or functional units thereof under one or more of the measures described above relative to the performance of other corporations or indicies. As part of the establishment of Company Performance Goals for a Plan Year, the Committee shall also establish a minimum level of achievement of the Company Performance Goals that must be met for a Participant to receive any portion of his Target Company Award. All of the provisions of this Section 6.2 are subject to the requirement that all Company Performance Goals shall be objective performance goals satisfying the requirement for “performance-based compensation” within the meaning of Section 162(m)(4) of the Code and the related regulations.

6.3

Payment of an Earned Company Award. At the time the Target Company Award for a Participant is established, the Committee shall prescribe a formula to determine the percentage (which may exceed 100%) of the Target Company Award which may be payable to the Participant based upon the degree of attainment of the Company Performance Goals during the Plan Year. Such formula may be expressed in terms of a graph or chart in which the amount that may be payable to a Participant is dependent upon the combined degree of attainment of more than one Company Performance Goal. If the minimum level of achievement

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of Company Performance Goals established by the Committee for a Participant for a Plan Year is not met, no payment of an Earned Company Award will be made to the Participant for that Plan Year. To the extent that the minimum level of achievement of Company Performance Goals is satisfied or surpassed for a Participant for a Plan Year, and upon written certification by the Committee that the Company Performance Goals have been satisfied to a particular extent and that any other material terms and conditions of the Target Company Awards have been satisfied, payment of an Earned Company Award shall be made to the Participant for that Plan Year in accordance with the prescribed formula except that, unless and until a Change of Control occurs, the Committee may determine, in its sole discretion, to reduce or eliminate the payment to be made.

6.4	Maximum Payable. The maximum amount payable to a Participant pursuant to this Article VI for performance for any Plan Year shall be $2,000,000.

6.5	Committee Discretion. Notwithstanding Articles III and V herein, the Committee shall not have discretion to modify the terms of Target Company Awards or the formula for calculating Earned Company Awards, except as specifically set forth in this Article VI.

VII.

FORM AND TIME OF PAYMENT OF AWARDS

Earned Award payments, if any, to be made for a Plan Year under Articles V and VI shall be paid, in cash, as soon as practicable after the end of the Plan Year during which the award was earned, but in no event later than the 15th day of the third month after the end of such Plan Year, except to the extent the Participant has elected to defer payment pursuant to the terms of any applicable plan, contract or other arrangement of Energy Corp. or a subsidiary permitting such deferral. The Committee shall be permitted to delay or accelerate a payment upon such events and conditions as may be prescribed under Code Section 409A and any regulations or generally applicable guidance issued thereunder.

VIII.

SEPARATION FROM SERVICE

8.1

Separation from Service Due to Death, Disability, or Retirement. In the event a Participant incurs a Separation from Service by reason of death, total and permanent disability (as determined by the Committee), or retirement (as determined by the Committee) during a Plan Year and such separation does not occur within twenty-four (24) months after a Change of Control, the Earned Award, determined in accordance with Section 5.4 and Section 6.3 herein, for such Plan Year shall be reduced to reflect participation prior to such Separation from Service. This reduction shall be determined by multiplying said Earned Award by a fraction; the numerator of which is the months of participation through the date of separation rounded up to whole months and the denominator of which is 12. The Earned Award thus determined for a Plan Year shall be paid as provided in Article VII.

8.2

Separation from Service for Other Reasons. In the event a Participant incurs a Separation from Service for any reason other than death, total and permanent disability (as determined by the Committee) or retirement (as determined by the Committee) during a Plan Year and such termination does not occur within twenty-four (24) months after a Change of Control, all of the Participant’s rights to an Earned Award for the Plan Year then in progress shall be forfeited; provided that, except in the event of a Separation from Service for cause (as determined in the sole discretion of the Committee and without regard to Section 10.2 hereof), the Committee, in its sole discretion, may pay the Earned Award, determined in accordance with Section 5.4 and Section 6.3 herein, for such Plan Year, reduced to reflect the prorated portion of that Plan Year that the Participant was employed by Energy Corp. or any of its subsidiaries, computed as determined by the Committee. The Earned Award thus determined for a Plan Year shall be paid as provided in Article VII.

IX.

BENEFICIARY DESIGNATION

Each Participant under the Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively and who may include a trustee under a will or living trust) to whom any benefit under the Plan is to be paid in case of his death before he received any or all of such benefit. Each designation will revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Committee during his lifetime. In the absence of any such designation, or if all designated beneficiaries predecease the Participant, benefits remaining unpaid at the Participant’s death shall be paid to the Participant’s estate.

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X.	CHANGE OF CONTROL

10.1

Termination Other than for Cause. Notwithstanding any other provisions of the Plan but subject to Section 10.3, in the event a Participant incurs a Separation from Service voluntarily or involuntarily for any reason other than for cause (with cause being determined by the Committee in accordance with Section 10.2 hereof), within twenty-four (24) months after a Change of Control, the Target Company Award and Target Individual Award, if any, established for the Participant for the Plan Year in progress at the time of the employment termination, prorated for the number of days in the Plan Year in which the Participant was employed by Energy Corp. or any of its subsidiaries, up to and including the date of separation, shall be paid to the Participant within ten (10) business days after the Separation from Service or, to the extent the Participant has elected to defer payment pursuant to the terms of any applicable plan, contract or other arrangement of Energy Corp. or a subsidiary permitting such deferral, deferred pursuant to the terms of such plan, contract or arrangement; provided, however, any such payment to a Participant pursuant to this Section 10.1 shall be reduced to the extent the Participant otherwise is entitled to receive payment of such Target Company Award or Target Individual Award pursuant to the terms of any employment agreement, plan, contract or other arrangement involving the Participant and Energy Corp. or any of its subsidiaries.

10.2

Termination for Cause. In the event a Participant incurs a Separation from Service for cause (as determined by the Committee in the manner hereinafter set forth) within twenty-four (24) months after a Change of Control, no Earned Award will be paid for the Plan Year in progress at the time of the Separation from Service; provided that, following a Change of Control, a Participant shall be deemed to have a Separation from Service for cause only if his employment was terminated involuntarily at the written direction of the Committee due solely to: (i) the willful and continued failure of the Participant to substantially perform his duties (other than any such failure resulting from physical or mental illness) for a minimum period of two weeks after receiving a written demand for substantial performance from the Committee which specifically identifies the manner in which the Committee or Chief Executive Officer believes that the Participant has not substantially performed his duties or (ii) the willful engaging by the Participant in illegal conduct or gross misconduct that is materially and demonstrably injurious to the Company.

10.3

(i) Notwithstanding anything in this Article X or any other provision of the Plan to the contrary, if, at the Participant’s Separation from Service, stock of the Company employing the Participant or any Affiliate thereof is publicly traded on an established securities market or otherwise and the Participant is a “Specified Employee” (as defined in Section 10.3(ii)) at the date of Separation from Service, then any payments otherwise payable under Section 10.1 to the Participant during the first six months following the Participant’s Separation from Service will be deferred until the earlier of (A) the first day of the seventh month following the Participant’s Separation from Service or (B) the Participant’s death. Any payments delayed as a result of the preceding sentence shall be accumulated and paid in a lump sum, without interest, as soon as practicable but not later than five (5) business days after the first day of the seventh month following the Participant’s Separation from Service (or the Participant’s earlier death).

(ii) For purposes of the Plan, a “Specified Employee” means, during the 12-month period beginning on April 1st of 2008 or on April 1st of any subsequent calendar year, an employee of the employing Company or its Affiliates who met the requirements of Section 416(i)(1)(A)(i), (ii) or (iii) of the Code (applied in accordance with the regulations thereunder and without regard to Code Section 416(i)(5)) for being a “key employee” at any time during the 12-month period ending on the December 31st immediately preceding such April 1st.

XI.

MISCELLANEOUS

11.1	Nontransferability. No Participant shall have the right to anticipate, alienate, sell, transfer, assign, pledge or encumber his or her right to receive any award made under the Plan until such an award becomes payable to him or her.

11.2	No Right to Company Assets. Any benefits which become payable hereunder shall be paid from the general assets of Energy Corp. or applicable subsidiary. No Participant shall have any lien on any assets of the Company by reason of any award made under the Plan.

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11.3

No Implied Rights; Employment. The adoption of the Plan or any modification or amendment hereof does not imply any commitment to continue or adopt the same plan, or any modification thereof, or any other plan for incentive compensation for any succeeding year, provided, that no such modification or amendment shall adversely affect the rights of any person, without his or her written consent, under any award theretofore granted under the Plan unless such modification or amendment is made in order to cause the Plan or award to comply with, or qualify for an exemption from, Code Section 409A and the regulations promulgated thereunder. Neither the Plan nor any award made under the Plan shall create any employment contract between the Company and any Participant.

11.4.

Participation. No Participant or other employee shall at any time have a right to be selected for participation in the Plan for any Plan Year, despite having been selected for participation in a prior Plan Year. Nothing in this Plan shall interfere with or limit in any way the right of the Company to terminate any Participant’s employment at any time, nor confer upon any Participant any right to continue in the employ of the Company.

11.5	All Determinations Final. All determinations of the Committee or the Board as to any disputed questions arising under the Plan, including questions of construction and interpretation, shall be final, binding and conclusive upon all Participants and all other persons and shall not be reviewable.

11.6

Plan Description. Each Participant shall be provided with a Plan description and a Plan agreement for each Plan Year which shall include Target Individual Awards, individual performance goals, Target Company Awards, Company Performance Goals and a Performance Matrix for each year. In the event of a conflict between the terms of the Plan description and the Plan, the terms of the Plan shall control unless the Committee decides otherwise.

11.7	Successors. This Plan shall be binding on the successors and assigns of Energy Corp.

11.8	Section 409A Compliance. To the extent applicable, it is intended that this Plan be in full compliance with the provisions of Section 409A of the Code and the regulations thereunder. The Plan shall be interpreted, construed and administered in a manner consistent with this intent.

11.9

Tax Penalty Avoidance. The provisions of this Plan are not intended, and should not be construed to be legal, business or tax advice. The Company, Participants and any other party having any interest herein are hereby informed that the U.S. federal tax advice contained in this document (if any) is not intended or written to be used, and cannot be used, for the purpose of (i) avoiding penalties under the Code or (ii) promoting, marketing or recommending to any party any transaction or matter addressed herein.

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OGE Energy Corp.

2007 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 related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.

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

Enogex Inc. and its subsidiaries (“Enogex”) are a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage, pursuant to which Enogex provides (a) fee-based intrastate transportation services on a firm and interruptible basis and, pursuant to Section 311 of the Natural Gas Policy Act, as amended, interstate transportation services on an interruptible basis and (b) fee-based firm and interruptible storage services to third parties at market-based rates; and (2) natural gas gathering and processing, pursuant to which Enogex provides well connect, gathering, measurement, treating, dehydration, compression and processing services to its producer customers primarily in the Arkoma and Anadarko basins, including those operating in the Granite Wash play and Atoka play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma.

Historically, Enogex had also engaged in natural gas marketing through its subsidiary, OGE Energy Resources, Inc. (“OERI”). In connection with the proposed initial public offering of common units of OGE Enogex Partners L.P., a Delaware limited partnership (the “Partnership”), on January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Enogex’s historical consolidated financial statements were prepared from Enogex’s books and records related to Enogex’s operating assets. Accordingly, the discussion that follows includes the results of OERI, but as of January 1, 2008, Enogex no longer has any interest in the results of OERI.

In May 2007, the Company formed the Partnership as part of its strategy to further develop Enogex’s natural gas midstream assets and operations. The Partnership has filed a registration statement with the Securities and Exchange Commission for a proposed initial public offering of its common units, representing limited partner interests in the Partnership (the “Offering”). At the date of this annual report, the registration statement relating to the Offering is not effective. Prior to the closing of the Offering, Enogex Inc., which is currently an Oklahoma corporation, would convert to Enogex LLC, a Delaware limited liability company. In connection with the Offering, the Company is expected to contribute an approximately 25 percent membership interest in Enogex LLC to a wholly owned subsidiary of the Partnership that would serve as Enogex LLC’s managing member and would control its assets and operations. A wholly owned subsidiary of the Company will retain the remaining approximately 75 percent membership interest in Enogex LLC. It is currently contemplated that at the completion of the Offering, the Company will indirectly own an approximate 68 percent limited partner interest and a two percent general partner interest in the Partnership.

The completion of the Offering is subject to numerous conditions and no assurances can be made that it will be successfully completed. The Company expects to continue to evaluate strategic alternatives for Enogex, including other transactions that the Company believes could provide long-term value to its shareowners and the proposed initial public offering. The securities offered under the registration statement may not be sold, nor may offers to buy be accepted, prior to the time that the registration statement becomes effective. The information contained in this annual report with respect to the Offering shall not constitute an offer to sell or a solicitation of an offer to buy any securities.

From a financial reporting perspective, the formation of the Partnership had no effect on the Company’s financial statements as of and for the periods ended December 31, 2007, 2006 and 2005. In the event that, and beginning with the period in which, the Offering is completed, the Company will consolidate the results of the Partnership with minority interest treatment for the common units of the Partnership owned by unitholders other than the Company or its consolidated subsidiaries.

Executive Overview

Strategy

The Company’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream gas business. The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth, maintenance of a dividend payout ratio consistent with its peer group and maintenance of strong credit ratings. The Company believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

OG&E has been focused on increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, OG&E has taken, or has committed to take, the following actions:

•

OG&E purchased a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) in July 2004;

•

OG&E entered into an agreement in February 2006 to engineer, procure and construct a wind generation energy system for a 120 MW wind farm (“Centennial”) in northwestern Oklahoma. The wind farm was fully in service in January 2007;

•

OG&E announced in early 2007a six-year construction initiative that is estimated to include up to $2.4 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. OG&E’s six-year construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure;

•

OG&E announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, OG&E expects to issue a request for proposal in the first quarter of 2008;

•

OG&E announced its desire to begin building a high-capacity transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle that would be used by OG&E and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states;

•

OG&E has also previously committed to the Southwest Power Pool (“SPP”) to build the Oklahoma portion of the western half of the SPP “X-Plan” that includes transmission lines from Woodward to Tuco, Texas and from Woodward to Spearville, Kansas;

•

OG&E entered into agreements in January 2008 to purchase a 51 percent ownership interest in the 1,230 MW Redbud power plant; and

•

With the previously announced six-year construction initiative discussed above, and including the acquisition of the Redbud power plant, OG&E’s 2008 to 2013 capital expenditures are expected to be approximately $3.0 billion.

The increase in wind power generation, the building of the transmission lines and the acquisition of the Redbud power plant are all subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP. Other projects involve installing new emission-control and monitoring equipment at existing OG&E power plants to help meet OG&E’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 17 of Notes to Consolidated Financial Statements.

Results of operations from the transportation and storage business are determined primarily by the volumes of natural gas transported on Enogex’s intrastate pipeline system, volumes of natural gas stored at Enogex’s storage facilities and the level of fees charged to Enogex’s customers for such services. Enogex generates a majority of its revenues and margins for its pipeline business under fee-based transportation contracts that are directly related to the volume of natural gas capacity reserved on its system. The margin Enogex earns from its transportation activities is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, Enogex’s revenues from these arrangements would be reduced. Results of operations from the gathering and processing business are determined primarily by the volumes of natural gas Enogex gathers and processes, its current contract portfolio and natural gas and

natural gas liquids (“NGL”) prices. Because of the natural decline in production from existing wells connected to Enogex’s systems, Enogex’s success depends on its ability to gather new sources of natural gas, which depends on certain factors beyond its or our control. Any decrease in supplies of natural gas could adversely affect Enogex’s gathering and processing business. As a result, Enogex’s cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on its gathering systems and the asset utilization rates at its natural gas processing plants, Enogex must continually obtain new natural gas supplies. The primary factors affecting Enogex’s ability to obtain new supplies of natural gas and attract new customers to its assets depends in part on the level of successful drilling activity near these systems, Enogex’s ability to compete for volumes from successful new wells and Enogex’s ability to expand capacity as needed.

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects and increased utilization of existing assets and strategic acquisitions. 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. Over the past several years, Enogex has initiated multiple organic growth projects. Currently, Enogex’s organic growth capital expenditures are focused on three primary areas:

•

upgrades to Enogex’s existing transportation system due to increased volumes as a result of the broader shift of gas flow from the Rocky Mountains and the mid-continent to markets in the northeast and southeast United States;

•

expansions on the east side of Enogex’s gathering system, primarily in the Woodford Shale play in southeastern Oklahoma through the construction of new facilities and expansion of existing facilities and its interest in the joint venture, Atoka Midstream LLC; and

•

expansions on the west side of Enogex’s gathering system, primarily in the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle.

For additional information regarding current or recently completed projects, see Note 16 of Notes to Consolidated Financial Statements.

In addition to focusing on growing its earnings, Enogex has reduced its exposure to changes in commodity prices and minimized its exposure to keep-whole processing arrangements. Enogex’s profitability increased significantly from 2003 to 2007 due to the performance improvement plan initiated in 2002 as well as an overall favorable business environment coupled with higher commodity prices. While the Company believes substantial progress has been achieved, additional opportunities remain. Enogex continues to review its work processes, evaluate the rationalization of assets, negotiate better terms for both new contracts and replacement contracts, manage costs and pursue opportunities for organic growth, all in an effort to further improve its cash flow and net income, while at the same time decreasing the volatility associated with commodity prices.

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

Summary of Operating Results

2007 compared to 2006. The Company reported net income of approximately $244.2 million, or $2.64 per diluted share, in 2007 as compared to approximately $262.1 million, or $2.84 per diluted share, in 2006. The decrease in net income of approximately $17.9 million, or $0.20 per diluted share, during 2007 as compared to 2006 was primarily due to:

•

an increase in net income at OG&E of approximately $12.4 million, or $0.13 per diluted share of the Company’s common stock, in 2007 as compared to 2006 primarily due to a higher gross margin from higher rates from the Centennial wind farm rider, security rider and Arkansas rate case, increased peak demand and related revenues by non-residential customers in OG&E’s service territory and new customer growth in OG&E’s service territory partially offset by cooler weather in OG&E’s service territory. Also contributing to the increase in net income was lower interest expense and lower income tax expense partially offset by higher depreciation expense;

•

a decrease in net income at Enogex (including discontinued operations) of approximately $27.3 million, or $0.30 per diluted share of the Company’s common stock, in 2007 as compared to 2006, of which $0.39 per diluted share was due to a reduction in earnings associated with discontinued operations. This decrease was partially offset by an increase of approximately $0.09 per diluted share associated with continuing operations primarily due to higher

gross margins in each of Enogex’s segments partially offset by higher operation and maintenance expenses, lower other income and higher income tax expense; and

•

a net loss at OGE Energy of approximately $3.7 million, or $0.04 per diluted share of the Company’s common stock, in 2007, as compared to a net loss of approximately $0.7 million, or $ 0.01 per diluted share, in 2006 primarily due to an income tax adjustment recorded in 2006.

Enogex’s net income for 2007 was approximately $86.2 million, which included OERI’s recorded losses of approximately $2.2 million resulting from recording natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory are expected to be realized during the first quarter of 2008.

2006 compared to 2005. The Company reported net income of approximately $262.1 million, or $2.84 per diluted share, in 2006 as compared to approximately $211.0 million, or $2.32 per diluted share, in 2005. The increase in net income of approximately $51.1 million, or $0.52 per diluted share, during 2006 as compared to 2005 was primarily due to:

•

an increase in net income at OG&E of approximately $19.6 million, or $0.19 per diluted share of the Company’s common stock, in 2006 as compared to 2005 primarily due to a higher gross margin from a price variance primarily due to rate increases and new customer growth and increased usage in OG&E’s service territory. These increases were partially offset by higher operation and maintenance expenses, higher interest expense and higher income tax expense;

•

an increase in net income at Enogex (including discontinued operations) of approximately $23.7 million, or $0.24 per diluted share of the Company’s common stock, in 2006 as compared to 2005 primarily due to higher gross margins in each of Enogex’s segments which was partially offset by higher other operation and maintenance expense and higher income tax expense and a reduction of $0.16 per diluted share attributable to discontinued operations; and

•

a net loss at OGE Energy of approximately $0.7 million, or $0.01 per diluted share of the Company’s common stock, in 2006 as compared to a net loss of approximately $8.5 million, or $0.10 per diluted share, in 2005 primarily due to higher income tax benefits in 2006 as a result of recording the Employee Stock Ownership Plan (“ESOP”) dividend deduction at OGE Energy in 2006 which was previously recorded at OG&E in 2005.

Enogex’s net income for 2006 was approximately $113.5 million, which included OERI’s recorded losses of approximately $6.3 million resulting from recording natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2007.

OERI’s results of operations are included in the historical financial and operating data rather than in discontinued operations because subsequent to the distribution of the stock of OERI to OGE Energy it is anticipated that the ongoing transactions between OERI and Enogex will constitute a significant continuation of activities and cash flows for Enogex.

Recent Developments and Regulatory Matters

Proposed Acquisition of Power Plant

On January 21, 2008, OG&E entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which are indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, OG&E agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which currently owns a 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“Redbud Facility”), for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.

In connection with the Purchase and Sale Agreement, OG&E also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”), pursuant to which OG&E agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which OG&E, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and OG&E will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its

pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.

The transactions described above are subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, an order from the FERC authorizing the contemplated transactions, an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions. OG&E will not be obligated to complete the transactions if the orders from the FERC and the OCC contain any conditions or restrictions which are materially more burdensome than those proposed in OG&E’s applications. Either OG&E or the Redbud Sellers may terminate the Purchase and Sale Agreement if the closing has not occurred on or prior to November 16, 2008; provided that the Redbud Sellers have the option to extend such deadline for up to an additional 180 days if the sole reason the closing has not occurred is because the governmental and regulatory approvals have not been obtained. There can be no assurances that the transactions will be completed or as to its ultimate timing. OG&E expects to file an application with the OCC in March 2008 asking the OCC to approve the prudency of the transactions and an appropriate reasonable recovery mechanism. The OCC rules provide that the OCC has up to 240 days to issue an order determining OG&E’s pre-approval request. Absent a settlement, the earliest OG&E expects an order from the OCC is November 2008.

Cancelled Red Rock Power Plant

On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of, Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Consolidated Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. OG&E expects to receive an order from the OCC in this matter by the end of 2008.

OCC Order Confirming Savings / Acquisition of McClain Power Plant

The 2002 agreed-upon settlement of an OG&E rate case (“2002 Settlement Agreement”) required that, if OG&E did not acquire electric generation of not less than 400 MW (“New Generation”) by December 31, 2003, OG&E must credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. On July 9, 2004, OG&E completed the acquisition of the McClain Plant that was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire New Generation. On June 7, 2007, OG&E filed an application with the OCC supporting its compliance with the 2002 Settlement Agreement. On November 21, 2007, OG&E received an order from the OCC affirming that the acquisition of the McClain Plant provided savings to OG&E’s Oklahoma customers in excess of the required $75 million over the three-year period from January 1, 2004 through December 31, 2006.

Pipeline Lease Project

In December 2006, Enogex entered into a firm capacity lease agreement with Midcontinent Express Pipeline, LLC (“MEP”) for a primary term of 10 years (subject to possible extension) that would give MEP and its shippers access to capacity on Enogex’s system. The quantity of capacity subject to the MEP lease agreement is currently 275 million cubic feet per day (“MMcf/d”) with the quantity ultimately to be leased subject to being increased by mutual agreement pursuant to the lease agreement. In addition to MEP’s lease of Enogex’s capacity, the proposed MEP project includes construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Pending necessary regulatory approval, the MEP project is currently expected to be in service during the first quarter of 2009. Enogex currently estimates that its capital expenditures related to this project will be approximately $86 million. The lease agreement with MEP is subject to certain contingencies, including regulatory approval. Prior to that approval, Enogex may incur expenditures of between approximately $20 million and $40 million primarily related to commitments for materials that can be sold or used in normal operations in the event the MEP project does not proceed. The amount not recovered or utilized for such expenditures is not expected to be material.

filed an application with the FERC for issuance of a limited jurisdiction certificate authorizing its lease agreement with MEP. Certain Enogex shippers have filed motions to intervene in Enogex’s FERC certificate proceeding, and some have protested Enogex’s certificate application. Protestors have claimed that it is unduly discriminatory for Enogex to propose to lease capacity to MEP while not generally offering firm interstate transportation service, that the lease arrangement will adversely affect the availability of interruptible interstate transportation service on the Enogex system and that the lease payment specified under the MEP lease agreement is unduly preferential in MEP’s favor. These protestors have urged the FERC to reject the MEP lease arrangement or to condition its acceptance on a requirement that Enogex offer existing shippers taking interruptible interstate service the opportunity to convert that service to firm service. One protestor has asked the FERC to consolidate the Enogex certificate proceeding with Enogex’s Section 311 triennial rate proceeding currently pending before the FERC. While Enogex cannot predict what action the FERC may take regarding the lease agreement, Enogex believes that the proposed MEP lease arrangement is consistent with FERC policy and precedent involving similar lease arrangements.

On January 18, 2008, Enogex filed a 30-day advance notice to advise the FERC of its intended construction of the Bennington Station Facilities. In that notice, Enogex described the environmental impacts likely to be associated with construction and operation of a new 24,000 horsepower transmission compressor station and associated pipeline that Enogex proposes to construct to support its provision of pipeline capacity under its capacity leases including the lease with MEP. Enogex believes that it has complied with all applicable requirements of the FERC’s regulations pertaining to an intrastate pipeline’s construction of facilities under Section 311 of the Natural Gas Policy Act, as amended. The FERC did not take any action with respect to Enogex’s advance notice filing and Enogex has begun construction of the Bennington Station Facilities.

Southeastern Oklahoma / East Side Expansions

Enogex is expanding in the Woodford Shale play and has several projects either completed or scheduled for completion in 2007 and 2008. For example, in December 2006, Enogex entered into a joint venture arrangement with Pablo Gathering, LLC, a subsidiary of Pablo Energy II, LLC, a Texas-based exploration and production company. The joint venture, Atoka Midstream LLC, constructed, owns and/or operates a gathering system and processing plant and related facilities relating to production in certain areas in southeastern Oklahoma. The gathering system and processing plant were placed in service during the third quarter of 2007. Enogex owns a 50 percent membership interest in Atoka Midstream and acts as the managing member and operator of the facilities owned by the joint venture.

Texas Panhandle / West Side Expansions

In August 2006, Enogex completed a project to expand its gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed Enogex to benefit from growth opportunities in that marketplace. This project included the addition of a 20-inch gathering header that is intended to be used to collect gas from producers and deliver the gas to multiple outlets and processing plants.

In February 2008, Enogex completed construction on the first phase (22 miles) of a new 30-mile pipeline project that will connect Enogex’s Hughes, Coal and Pittsburgh county gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma. The gathering project created additional gathering capacity of 125 MMcf/d for customers desiring low-pressure services with the potential to double this amount with incremental compression investments. The pipeline is complemented by approximately 20,000 horsepower of compression providing reliable gathering and take-away capacity for its Woodford Shale customers, who now have access to 350 MMcf/d to 500 MMcf/d of existing take-away capacity on Enogex’s mainline pipeline. Also, Enogex recently committed to approximately $50 million in additional expansions in this area primarily during 2008 and 2009 and expects its latest expansion project to be in service by the third quarter of 2008.

Enogex continues to review growth opportunities to expand this project and has recently begun several additional new projects to continue expansion on the west side of its system. In addition, Enogex has installed approximately 11.5 miles of 12-inch pipeline and added approximately 5,400 horsepower of compression to its Billy Rose compressor station.

2008 Outlook

The Company’s earnings guidance for 2008 is between $223 million and $242 million of net income or $2.40 to $2.60 per diluted share assuming approximately 93.1 million average diluted shares outstanding, cash flow from operations of between $483 million and $502 million and an effective tax rate of 33.5 percent.


(In millions, except per share data)	Dollars	Diluted EPS
OG&E	$145 - $155	$1.56 - $1.66
Enogex	$83 - $91	$0.89 - $0.98
Holding Company	($5) - ($4)	($0.05) - ($0.04)
Total	$223 - $242	$2.40 - $2.60

Key assumptions for 2008 are:

OG&E

As shown above, OG&E’s earnings guidance for 2008 is between $145 million to $155 million, or $1.56 to $1.66 per diluted share of the Company’s common stock. Key factors and assumptions underlying this guidance include:

•

Normal weather patterns are experienced for the remainder of the year;

•

Gross margin on weather-adjusted, retail electric sales increases approximately two percent;

•

Operating expenses of approximately $536 million;

•

Interest costs of approximately $77 million;

•

An effective tax rate of approximately 31.1 percent; and

•

Capital expenditures for investment in OG&E’s generation, transmission and distribution system of approximately $789 million in 2008, which includes capital expenditures in the amount of approximately $435 million associated with OG&E’s planned acquisition of the Redbud generating plant.

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

Enogex

As shown above, Enogex’s earnings guidance is $83 million to $91 million, or $0.89 to $0.98 per diluted share of the Company’s common stock. Key factors and assumptions underlying this guidance include:

•

Total Enogex anticipated gross margin of approximately $376 million to $390 million. The 2008 guidance assumes:

•

Transportation and storage gross margin contribution of approximately $141 million.

•

Gathering and processing gross margin contribution of approximately $235 million to $249 million. Key factors affecting the gathering and processing gross margin forecast are:

•

Assumed increase of eight percent in gathered volumes over 2007;

•

Assumed natural gas prices of $7.25 to $7.64 per Million British thermal unit (“MMBtu”) in 2008;

•

Assumed realized commodity spreads of $5.48 to $6.09 per MMBtu in 2008. The realized commodity spread takes into account that 59 percent of processing volumes that bear price risk are hedged;

•

Assumed weighted average natural gas liquids prices of $1.20 to $1.27 per gallon in 2008;

•

Operating expenses of approximately $201 million;

•

Interest expense of approximately $30 million in 2008; and

•

Capital expenditures for investment in Enogex’s pipeline system of approximately $292 million in 2008.

Holding Company

As shown above, the projected loss at the holding company is between $4 million and $5 million, or $0.04 to $0.05 per diluted share, primarily due to interest expense relating to long and short-term debt borrowings.

Dividend Policy

The Company’s dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends no more than 65 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder

base, our financial position, our growth targets, the composition of our assets and investment opportunities. At the Company’s November 2007 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.3475 per share from $0.34 per share effective with the Company’s first quarter 2008 dividend.

Results of Operations

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the years ended December 31, 2007, 2006 and 2005 and the Company’s consolidated financial position at December 31, 2007 and 2006. 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.

Year ended December 31 (In millions, except per share data)	2007	2006	2005
Operating income	$ 455.3	$ 432.7	$ 322.4
Net income	$ 244.2	$ 262.1	$ 211.0
Basic average common shares outstanding	91.7	91.0	90.3
Diluted average common shares outstanding	92.5	92.1	90.8
Basic earnings per average common share	$ 2.66	$ 2.88	$ 2.34
Diluted earnings per average common share	$ 2.64	$ 2.84	$ 2.32
Dividends declared per share	$ 1.3675	$ 1.3375	$ 1.33

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 the cost of capital and income taxes.

Operating Income (Loss) by Business Segment

Year ended December 31 (In millions)	2007	2006	2005
OG&E (Electric Utility)	$ 292.0	$ 293.9	$ 232.2
Enogex (Natural Gas Pipeline)
Transportation and storage	55.0	54.7	37.3
Gathering and processing	91.4	79.8	58.5
Marketing	17.1	4.3	(6.2)
Other Operations (A)	(0.2)	---	0.6

Consolidated operating income	$ 455.3	$ 432.7	$ 322.4

(A) Other Operations primarily includes consolidating eliminations.

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

OG&E

Year ended December 31 (Dollars in millions)	2007	2006	2005
Operating revenues	$ 1,835.1	$ 1,745.7	$ 1,720.7
Cost of goods sold	1,025.1	950.0	994.2
Gross margin on revenues	810.0	795.7	726.5
Other operation and maintenance	320.7	316.5	309.2
Depreciation	141.3	132.2	134.4
Taxes other than income	56.0	53.1	50.7
Operating income	292.0	293.9	232.2
Interest income	---	1.9	2.6
Allowance for equity funds used during construction	---	4.1	---
Other income (loss)	5.0	4.0	(2.8)
Other expense	7.2	9.7	2.5
Interest expense	54.9	60.1	47.2
Income tax expense	73.2	84.8	52.6
Net income	$ 161.7	$ 149.3	$ 129.7
Operating revenues by classification
Residential	$ 706.4	$ 698.8	$ 663.6
Commercial	450.1	428.3	418.9
Industrial	221.4	215.7	220.8
Oilfield	140.9	129.3	134.8
Street light	9.1	11.4	12.2
Public authorities	172.3	159.6	160.9
Sales for resale	68.8	65.4	67.7
Provision for rate refund	0.1	(0.9)	(2.0)
System sales revenues	1,769.1	1,707.6	1,676.9
Off-system sales revenues	35.1	2.7	4.9
Other	30.9	35.4	38.9
Total operating revenues	$ 1,835.1	$ 1,745.7	$ 1,720.7
MWH (A) sales by classification (in millions)
Residential	8.7	8.7	8.5
Commercial	6.3	6.2	6.0
Industrial	4.2	4.4	4.5
Oilfield	2.8	2.7	2.6
Street light	0.1	0.1	0.1
Public authorities	2.9	2.8	2.8
Sales for resale	1.4	1.5	1.5
System sales	26.4	26.4	26.0
Off-system sales	0.7	---	0.1
Total sales	27.1	26.4	26.1
Number of customers	762,234	754,840	745,493
Average cost of energy per KWH (B) - cents
Natural gas	6.872	6.829	8.378
Coal	1.143	1.114	1.004
Total fuel	3.173	3.003	3.234
Total fuel and purchased power	3.523	3.366	3.557
Degree days (C)
Heating - Actual	3,175	2,746	3,159
Heating - Normal	3,631	3,631	3,631
Cooling - Actual	2,221	2,485	2,163
Cooling - Normal	1,911	1,911	1,911

(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.

2007 compared to 2006. OG&E’s operating income decreased approximately $1.9 million, or 0.7 percent, in 2007 as compared to 2006 primarily due to higher depreciation expense, higher taxes other than income and higher operation and maintenance expenses partially offset by a higher gross margin.

Gross Margin

Gross margin was approximately $810.0 million in 2007 as compared to approximately $795.7 million in 2006, an increase of approximately $14.3 million, or 1.8 percent. The gross margin increased primarily due to:

•

higher rates from the Centennial wind farm rider, security rider and Arkansas rate case, which increased the gross margin by approximately $25.1 million;

•

increased peak demand and related revenues by non-residential customers in OG&E’s service territory, which increased the gross margin by approximately $9.4 million; and

•

new customer growth in OG&E’s service territory, which increased the gross margin by approximately $9.1 million.

These increases in the gross margin were partially offset by:

•

cooler weather in OG&E’s service territory resulting in an approximate 11 percent decrease in cooling degree days compared to 2006, which decreased the gross margin by approximately $16.3 million; and

•

price variance due to sales and customer mix, which decreased the gross margin by approximately $13.6 million.

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $756.1 million in 2007 as compared to approximately $730.3 million in 2006, an increase of approximately $25.8 million, or 3.5 percent, primarily due to increased natural gas generation in 2007 and a gain recognized from the sale of sulfur dioxide allowances of approximately $8.9 million in 2006. 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 2007, OG&E’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. In 2006, OG&E’s fuel mix was 67 percent coal and 33 percent natural gas. Purchased power costs were approximately $268.6 million in 2007 as compared to approximately $219.7 million in 2006, an increase of approximately $48.9 million, or 22.3 percent. This increase was primarily due to OG&E’s entrance into the energy imbalance service market on February 1, 2007 (see Note 17 of Notes to Consolidated Financial Statements for a further discussion).

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. 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.

Operating Income

Other operation and maintenance expenses were approximately $320.7 million in 2007 as compared to approximately $316.5 million in 2006, an increase of approximately $4.2 million, or 1.3 percent. The increase in other operation and maintenance expenses was primarily due to:

•

an increase in outside services expense of approximately $12.9 million primarily due to planned overhaul expenses at the power plants;

•

higher salaries, wages and other employee benefits expense of approximately $6.7 million; and

•

an increase in fees and permits expense of approximately $2.2 million due to additional fees to the SPP.

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

•

an increase of capitalized work of approximately $17.7 million primarily related to storm costs that were deferred as a regulatory asset in 2007; and

•

a decrease of approximately $2.2 million of an additional accrual due to a settlement of a claim in 2006.

Depreciation expense was approximately $141.3 million in 2007 as compared to approximately $132.2 million in 2006, an increase of approximately $9.1 million, or 6.9 percent, primarily due to the Centennial wind farm being placed in service during January 2007.

Taxes other than income were approximately $56.0 million in 2007 as compared to approximately $53.1 million in 2006, an increase of approximately $2.9 million, or 5.5 percent, primarily due to increased ad valorem tax accruals and increased payroll tax expenses.

Additional Information

Interest Income. There was no interest income in 2007 as compared to approximately $1.9 million in 2006. The decrease was primarily due to interest income earned on fuel under recoveries in 2006 while there was a fuel over recovery balance in 2007.

Allowance for Equity Funds Used During Construction. There was no allowance for equity funds used during construction in 2007 as compared to approximately $4.1 million in 2006, a decrease of approximately $4.1 million primarily due to construction costs for the Centennial wind farm that exceeded the average daily short-term borrowings in 2006.

Other Income. Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $5.0 million in 2007 as compared to approximately $4.0 million in 2006, an increase of approximately $1.0 million or 25.0 percent. The increase in other income was primarily due to an increase of approximately $3.6 million related to the guaranteed flat bill tariff resulting from more customers participating in this plan, along with milder weather in 2007. This was partially offset by a decrease of approximately $2.6 million associated with the tax gross up of allowance for equity funds used during construction in 2006 with no comparable item recorded in 2007.

Other Expense. Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $7.2 million in 2007 as compared to approximately $9.7 million in 2006, a decrease of approximately $2.5 million, or 25.8 percent, primarily due to a loss on the retirement of fixed assets of approximately $5.2 million in 2006 partially offset by the write-off of non-recoverable Red Rock expenses of approximately $3.1 million for Arkansas and the FERC jurisdictions in 2007.

Interest Expense. Interest expense was approximately $54.9 million in 2007 as compared to $60.1 million in 2006, a decrease of approximately $5.2 million, or 8.7 percent. The decrease in interest expense was primarily due to:

•

a settlement with the Internal Revenue Service (“IRS”) resulting in a reversal of interest expense of approximately $7.2 million in 2007; and

•

a decrease of approximately $7.0 million associated with the interest from a water storage facility in 2006.

These decreases in interest expense were partially offset by:

•

an increase of approximately $3.5 million in interest to OGE Energy;

•

an increase of approximately $1.7 million associated with the carrying charges in the over recovery on fuel from customers; and

•

an increase of approximately $1.7 million due to interest expense recorded on treasury lock agreements OG&E entered into related to the issuance of long-term debt by OG&E in January 2008.

Income Tax Expense. Income tax expense was approximately $73.2 million in 2007 as compared to approximately $84.8 million in 2006, a decrease of approximately $11.6 million, or 13.7 percent, primarily due to renewable energy tax credits for which OG&E became eligible in 2007 on the wind power production from OG&E’s Centennial wind farm partially offset by higher pre-tax income for OG&E.

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

Gross Margin

Gross margin was approximately $795.7 million in 2006 as compared to approximately $726.5 million in 2005, an increase of approximately $69.2 million, or 9.5 percent. The gross margin increased primarily due to:

•

price variance primarily due to rate increases authorized in the OCC order in December 2005, which increased the gross margin by approximately $47.6 million;

•

new customer growth in OG&E’s service territory, which increased the gross margin by approximately $10.9 million;

•

increased peak demand and related revenues by non-residential customers in OG&E’s service territory, which increased the gross margin by approximately $6.7 million; and

•

warmer weather in OG&E’s service territory, which increased the gross margin by approximately $6.2 million.

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

Operating Income

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

•

higher salaries, wages and other employee benefits of approximately $12.5 million;

•

higher allocations from OGE Energy of approximately $3.9 million primarily due to an increase in incentive compensation;

•

higher bad debt expense of approximately $3.5 million; and

•

an additional accrual of approximately $2.2 million for the settlement of a claim.

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

•

a decrease in outside services expense of approximately $9.3 million; and

•

an increase in capitalized work of approximately $6.4 million primarily due to increased labor and transportation expenses related to more capital projects in 2006.

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

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

•

a decrease in depreciation rates that was implemented January 1, 2006 as approved by the OCC in December 2005; and

•

a decrease due to the retirement of assets at June 30, 2006 related to a power supply contract with a large industrial customer that expired June 1, 2006.

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

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

Additional Information

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

Other Income (Loss). Other income was approximately $4.0 million in 2006 as compared to a loss of approximately $2.8 million in 2005, an increase of approximately $6.8 million. The increase in other income was primarily due to:

•

a gain of approximately $3.5 million from the sale of miscellaneous assets that were recorded in 2004 and were reclassified to a regulatory liability in 2005; and

•

the benefit associated with the tax gross-up of approximately $4.1 million of allowance for equity funds used during construction.

Other Expense. Other expense was approximately $9.7 million in 2006 as compared to approximately $2.5 million in 2005, an increase of approximately $7.2 million primarily due to a loss on the retirement of fixed assets in 2006.

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

•

increased interest of approximately $7.7 million due to the one-time recognition of interest expense associated with a water storage agreement;

•

increased interest of approximately $4.8 million on debt associated with the McClain Plant acquisition, which OG&E ceased recording as a regulatory asset on July 8, 2005;

•

increased interest of approximately $3.0 million due to the termination of an interest rate swap in 2005; and

•

increased interest of approximately $1.5 million due to increased borrowings from OGE Energy to cover increased construction costs.

These increases in interest expense were partially offset by:

•

a decrease in interest expense due to an increase in the allowance for borrowed funds used during construction of approximately $2.3 million; and

•

a decrease in interest expense of approximately $1.9 million related to the Company making a deposit with the IRS in August 2006 in anticipation that a portion of prior year deductions will be disallowed, which enabled OG&E to cease accruing interest in August 2006.

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

•

higher pre-tax income for OG&E;

•

the ESOP dividend deduction at OGE Energy in 2006 which was previously recorded at OG&E in 2005 of approximately $7.4 million; and

•

a decrease in state tax credits in 2006 of approximately $3.8 million.

Enogex – Continuing Operations

		Transportation		Gathering
Year Ended December 31, 2007		and Storage		and Processing		Marketing		Eliminations		Total
(In millions)
Operating revenues	$	230.4	$	799.4	$	1,537.9	$	(502.5)	$	2,065.2
Cost of goods sold		97.7		603.5		1,513.4		(502.5)		1,712.1
Gross margin on revenues		132.7		195.9		24.5		---		353.1
Other operation and maintenance		48.5		72.1		6.8		---		127.4
Depreciation		17.0		28.7		0.2		---		45.9
Impairment of assets		0.5		---		---		---		0.5
Taxes other than income		11.7		3.7		0.4		---		15.8
Operating income	$	55.0	$	91.4	$	17.1	$	---	$	163.5

		Transportation		Gathering
Year Ended December 31, 2006		and Storage		and Processing		Marketing		Eliminations		Total
(In millions)
Operating revenues	$	225.9	$	704.3	$	1,941.3	$	(503.7)	$	2,367.8
Cost of goods sold		100.3		536.7		1,927.1		(503.7)		2,060.4
Gross margin on revenues		125.6		167.6		14.2		---		307.4
Other operation and maintenance		41.2		59.5		9.3		---		110.0
Depreciation		17.9		24.2		0.2		---		42.3
Impairment of assets		---		0.3		---		---		0.3
Taxes other than income		11.8		3.8		0.4		---		16.0
Operating income	$	54.7	$	79.8	$	4.3	$	---	$	138.8

		Transportation		Gathering
Year Ended December 31, 2005		and Storage		and Processing		Marketing		Eliminations		Total
(In millions)
Operating revenues	$	246.4	$	644.5	$	3,995.3	$	(553.8)	$	4,332.4
Cost of goods sold		147.3		504.3		3,992.6		(553.8)		4,090.4
Gross margin on revenues		99.1		140.2		2.7		---		242.0
Other operation and maintenance		32.9		55.3		8.4		---		96.6
Depreciation		17.3		23.0		0.1		---		40.4
Taxes other than income		11.6		3.4		0.4		---		15.4
Operating income (loss)	$	37.3	$	58.5	$	(6.2)	$	---	$	89.6

Operating Data – Continuing Operations

Year Ended December 31	2007	2006	2005
New well connects (includes wells behind central receipt points) (A)	374	362	---
New well connects (excludes wells behind central receipt points)	178	206	223
Gathered volumes – TBtu/d (B)	1.05	0.98	0.92
Incremental transportation volumes – TBtu/d (C)	0.47	0.46	0.39
Total throughput volumes – TBtu/d	1.52	1.44	1.31
Natural gas processed – TBtu/d	0.57	0.54	0.52
Natural gas liquids sold (keep-whole) – million gallons	252	244	191
Natural gas liquids sold (purchased for resale) – million gallons	117	113	96
Natural gas liquids sold (percent-of-liquids) – million gallons	16	14	15
Total natural gas liquids sold – million gallons	385	371	302
Average sales price per gallon	$ 1.048	$ 0.902	$ 0.873

(A) Includes wells behind central receipt points (as reported to management by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site. This information is not available for years prior to 2006 as Enogex’s books and records were not maintained in a manner to provide this information for years prior to 2006.

(B) Trillion British thermal units per day.

2007 compared to 2006. Enogex’s operating income increased approximately $24.7 million in 2007 as compared to 2006 primarily due to a higher gross margin in each of Enogex’s segments, which was partially offset by higher operating expenses and higher depreciation expense.

Gross Margin

Enogex’s consolidated gross margin increased approximately $45.7 million in 2007 as compared to 2006. The increase resulted from a higher gross margin in the transportation and storage business ($7.1 million), the gathering and processing business ($28.3 million) and the marketing business ($10.3 million).

The transportation and storage business contributed approximately $132.7 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $125.6 million in 2006, an increase of approximately $7.1 million, or 5.7 percent. The transportation business contributed approximately $97.8 million of Enogex’s consolidated gross margin in 2007. The storage business contributed approximately $34.9 million of Enogex’s consolidated gross margin in 2007. The transportation and storage gross margin increased primarily due to:

•

a reduction in the lower of cost or market adjustments related to natural gas inventories used to operate the pipeline in 2006, which reduced the 2006 gross margin by approximately $8.3 million for which there was no comparable item in 2007;

•

increased storage demand fees due to entering into new contracts in 2007 with more favorable terms, which increased the gross margin by approximately $7.8 million;

•

a change in Enogex’s over-recovered position in its transportation business to an under-recovered position under its FERC-approved fuel tracker in the East Zone in 2007 as compared to 2006, which increased the gross margin by approximately $2.6 million;

•

the liability associated with a throughput contract which was transferred to the gathering and processing segment in the second quarter of 2007, which increased the gross margin by approximately $2.4 million; and

•

lower electric compression expense associated with its transportation business due to the decreased use of electric compression at Enogex’s Harrah processing plant following the loss of a contract during the second quarter of 2007, which increased the gross margin by approximately $1.3 million.

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

•

an increased imbalance liability, net of fuel recoveries and natural gas length positions, in its transportation business in 2007, which decreased the gross margin by approximately $6.7 million;

•

a decrease in the net gas sales margin in its transportation business due to a decrease in natural gas prices in 2007, which decreased the gross margin by approximately $3.3 million;

•

decreased commodity, interruptible and low and high pressure revenues in its transportation business of approximately $2.2 million in 2007 due primarily to renegotiation of contracts to demand-based contracts rather than commodity-based contracts in 2007; and

•

decreased commodity and interruptible revenues of approximately $1.1 million in 2007 due primarily to an interruptible storage contract that expired on September 30, 2006.

The gathering and processing business contributed approximately $195.9 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $167.6 million in 2006, an increase of approximately $28.3 million, or 16.9 percent. The gathering business contributed approximately $89.4 million of Enogex’s consolidated gross margin in 2007. The processing business contributed approximately $106.5 million of Enogex’s consolidated gross margin in 2007. The gathering and processing gross margin increased primarily due to:

•

an increase in keep-whole margins associated with its processing operations in 2007 as compared to 2006 primarily due to higher commodity spreads, which increased the gross margin by approximately $6.7 million;

•

reduced imbalance expense associated with its gathering operations resulting from the recognition in 2006 of an approximately $3.2 million imbalance liability upon the transfer of imbalances previously recognized in the transportation and storage business coupled with a decrease of an approximately $3.4 million imbalance liability, net of fuel recoveries and natural gas length positions, in 2007 as compared to 2006, which increased the gross margin by approximately $6.6 million;

•

increased condensate margin associated with its processing operations due to higher prices in 2007 as compared to 2006, which increased the gross margin by approximately $4.6 million;

•

renegotiated percent-of-liquids contracts associated with its processing operations entered into during 2007, which increased the gross margin by approximately $3.7 million;

•

higher fees associated with its gathering operations from low pressure contracts renegotiated with more favorable terms in 2007, which increased the gross margin by approximately $2.5 million;

•

sales of residue gas associated with its processing operations retained from the Atoka processing plant, which began operations in August 2007, that increased the gross margin by approximately $2.2 million;

•

higher compression fees associated with its gathering operations resulting from new business in 2007, which increased the gross margin by approximately $2.0 million;

•

an increase in new gathering business during 2007, which increased the gross margin by approximately $1.8 million; and

•

increased high pressure volumes associated with its gathering operations due to new production in 2007, which increased the gross margin by approximately $1.7 million.

These increases in the gathering and processing gross margin were partially offset by the settlement on a throughput contract in 2007 associated with its processing operations, which decreased the gross margin by approximately $1.9 million.

The marketing business contributed approximately $24.5 million of Enogex’s consolidated gross margin in 2007 as compared to approximately $14.2 million in 2006, an increase of approximately $10.3 million, or 72.5 percent. The marketing gross margin increased primarily due to:

•

realized gains from physical activity on a transportation contract, which increased the gross margin by approximately $32.7 million;

•

a reduction in lower of cost or market adjustments related to natural gas held in storage in 2007 as compared to 2006, which increased the gross margin by approximately $6.6 million; and

•

gains on physical sales of natural gas storage inventory activity partially offset by higher fees, which increased the gross margin by approximately $2.9 million.

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

•

lower gains on economic hedges of natural gas storage inventory from recording these hedges at market value on December 31, 2007 as compared to December 31, 2006, which decreased the gross margin by approximately $17.0 million;

•

lower gains on economic hedges associated with various transportation contracts from recording these hedges at market value on December 31, 2007 as compared to December 31, 2006, which decreased the gross margin by approximately $12.9 million; and

•

decreased gains from origination and other marketing and trading activity in 2007, which decreased the gross margin by approximately $2.0 million.

Operating Income

As shown above, Enogex’s operating income is calculated by subtracting from the gross margin the following four items: (i) other operation and maintenance expenses, (ii) depreciation, (iii) impairment of assets and (iv) taxes other than income. Enogex’s consolidated operating income in 2007 was approximately $163.5 million, a $24.7 million increase from its consolidated operating income in 2006. The increase was attributable primarily to the $45.7 million increase described above in consolidated gross margin, as the aggregate of other operation and maintenance expenses, depreciation expense, impairment of assets and taxes other than income was only approximately $21.0 million higher during 2007 as compared to 2006. The variances in depreciation expense and in taxes other than income on both a consolidated basis and by segment reflect differing levels of depreciable plant in service and a slight decrease in property taxes. The $17.4 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to:

•

higher salaries, wages and other employee benefits due to higher incentive compensation and hiring additional employees;

•

an increase in outside services, materials and supplies expense and office expense due to an increase in system projects in 2007; and

•

a sales and use tax refund received in the prior year.

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $7.3 million, or 17.7 percent, higher in 2007 as compared to 2006 primarily due to:

•

higher salaries, wages and other employee benefits expense of approximately $5.4 million primarily due to higher incentive compensation and hiring additional employees to support business growth;

•

an increase of approximately $4.7 million in outside services, materials and supplies expense and office expense due to an increase in system projects in 2007;

•

an increase of approximately $3.3 million due to a fee the marketing business began charging the transportation and storage business in 2007 related to hedging activities;

•

higher allocations from OGE Energy for overhead costs of approximately $2.1 million; and

•

an increase in professional services expense of approximately $1.2 million for legal and consultant costs for exploration of business expansion in 2007.

These increases were partially offset by:

•

lower internal allocations to the other Enogex segments for overhead costs of approximately $5.9 million; and

•

a decrease of approximately $1.2 million in rental expense due to the renegotiation of an office building lease in 2007 in addition to the expiration of a building lease in June 2006.

Other operation and maintenance expenses for the gathering and processing business were approximately $12.6 million, or 21.2 percent, higher in 2007 as compared to 2006 primarily due to:

•

higher allocations from the transportation and storage business and OGE Energy of approximately $6.8 million primarily due to increased costs in 2007;

•

a sales and use tax refund of approximately $2.0 million received in May 2006 related to activity in prior years with no corresponding item in 2007;

•

an increase of approximately $1.7 million in materials and supplies expense primarily due to an increase in system projects in 2007;

•

an increase of approximately $1.3 million in higher salaries, wages and other employee benefits expense primarily due to hiring additional employees to support business growth; and

•

an increase of approximately $1.0 million in higher compressor rental costs resulting from new business in 2007.

Other operation and maintenance expenses for the marketing business were approximately $2.5 million, or 26.9 percent, lower in 2007 as compared to 2006 primarily due to a fee of approximately $3.3 million the marketing business began charging Enogex in 2007 related to hedging activities partially offset by higher allocations of approximately $1.5 million primarily due to increased costs in 2007.

Enogex Consolidated Information

Interest Income. Enogex’s consolidated interest income was approximately $9.2 million in 2007 as compared to approximately $11.1 million in 2006, a decrease of approximately $1.9 million, or 17.1 percent, primarily due to interest income earned on cash investments from the cash proceeds from the sale of certain gas gathering assets in the Kinta, Oklahoma area (the “Kinta Assets”) in May 2006.

Other Income. Enogex’s consolidated other income was approximately $0.9 million in 2007 as compared to approximately $7.7 million in 2006, a decrease of approximately $6.8 million, or 88.3 percent. The decrease was primarily due to:

•

a pre-tax litigation settlement of approximately $5.2 million in 2006;

•

a pre-tax gain of approximately $1.0 million in the fourth quarter of 2006 from the sale of certain west Texas pipeline assets; and

•

a pre-tax gain of approximately $0.5 million in the first quarter of 2006 from the sale of small gathering sections of Enogex’s pipeline.

Income Tax Expense. Enogex’s consolidated income tax expense was approximately $53.5 million in 2007 as compared to approximately $48.0 million in 2006, an increase of approximately $5.5 million, or 11.5 percent, primarily due to higher pre-tax income.

Non-Recurring and Timing Items. In 2007, Enogex’s consolidated net income of approximately $86.2 million included OERI’s recorded losses of approximately $2.2 million resulting from recording natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory are expected to be realized during the first quarter of 2008. As discussed above, in connection with the Offering, on January 1, 2008, Enogex distributed its shares of common stock of OERI to OGE Energy. Also, in 2007, Enogex had a decrease in net income of approximately $0.3 million relating to an item that Enogex does not consider to be reflective of its ongoing performance related to an impairment of certain long-lived assets.

For 2006, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “Enogex—Discontinued Operations,” was approximately $113.5 million, which included OERI’s recorded losses of approximately $6.3 million resulting from recording natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2007. Also, in 2006, Enogex had an increase in net income of approximately $41.2 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These increases in consolidated net income include:

•

an after-tax gain on the sale of the Kinta Assets in the second quarter of 2006 of approximately $34.1 million;

•

the approximately $3.2 million after-tax impact of a litigation settlement;

•

income from discontinued operations of approximately $1.9 million;

•

a sales and use tax refund related to activity in prior years of approximately $1.3 million after tax;

•

an after-tax gain of approximately $0.6 million related to the sale of certain west Texas pipeline assets; and

•

an after-tax gain of approximately $0.3 million from the sale of a small gathering section of Enogex’s pipeline.

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

2006 compared to 2005

Enogex’s consolidated operating revenues and cost of goods sold decreased in 2006 approximately $2.0 billion, or 45.4 percent, and $2.0 billion, or 49.6 percent, respectively, as compared to 2005 primarily due to lower revenues and related costs in Enogex’s marketing business, reflecting a reduction in trading activities due to a shift in strategy in Enogex’s marketing business as Enogex continued to implement its refocused strategy that seeks to minimize the amount of capital employed and to complement better Enogex’s businesses.

Gross Margin

Enogex’s consolidated gross margin increased approximately $65.4 million in 2006 as compared to 2005 primarily due to increased gross margin in each of its businesses largely as a result of higher commodity spreads and business growth in 2006 as compared to 2005.

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

•

better management of gas pipeline imbalances as Enogex reduced its exposure to gas imbalances while taking advantage of favorable market price movement in 2006 and the transfer of certain imbalance liabilities previously carried by the transportation and storage business in 2005 to the gathering and processing business in 2006, which increased the gross margin by approximately $11.5 million in 2006;

•

increased commodity, interruptible and low and high pressure revenues primarily due to increased customer production and an increase in the allocated portion of bundled rates in 2006 resulting in increased rates of approximately $0.02 per MMBtu being recognized, which increased the gross margin by approximately $6.2 million in 2006;

•

a change in Enogex’s 2005 accounting estimate of the volume of natural gas in its natural gas storage inventory, which reduced the 2005 gross margin by approximately $5.7 million;

•

improved recovery of fuel as Enogex transitioned to zonal fuel rates in 2006, which increased the gross margin by approximately $4.7 million;

•

increased gross margin, recognized on natural gas sales of $0.628 per MMBtu as compared to 2005 due to favorable market conditions, which increased the gross margin by approximately $3.5 million; and

•

storage field hedging gains, which increased the gross margin by approximately $3.5 million.

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

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

•

increased net keep-whole margins primarily due to a $1.06 per MMBtu increase in natural gas prices coupled with an increase in NGL prices and increased volumes of 24.0 million gallons due to business growth, which increased the gross margin by approximately $25.3 million;

•

new percent-of-liquids contracts entered into during 2006, which increased the gross margin by approximately $6.0 million;

•

increased contractual fuel gains primarily due to an increase of approximately $1.33 per MMBtu in recognized natural gas market prices in 2006 as compared to 2005, which increased the gross margin by approximately $4.9 million;

•

new fixed fee contracts entered into during 2006, which increased the gross margin by approximately $2.8 million; and

•

a reduction in Enogex’s over-recovered fuel position as it transitioned to zonal fuel rates in 2006, which increased the gross margin by approximately $2.5 million.

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

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

•

gains in storage activity due to timing, resulting from recording Enogex’s storage hedges at market value at December 31, 2006 and an increase in storage capacity, which increased the gross margin by approximately $13.2 million;

•

a correction to the accounting procedure for park and loan transactions (natural gas storage transactions) in the first quarter of 2005, which decreased the gross margin in the first quarter of 2005 by approximately $7.7 million (see Note 15 of Notes to Consolidated Financial Statements); and

•

an increase in the spread between natural gas prices at the receipt location of the Cheyenne Hub near the Colorado and Wyoming border and the natural gas prices of the delivery locations in south central Kansas, which increased the gross margin by approximately $7.6 million.

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

•

a lower of cost or market adjustment related to natural gas in storage during 2006, which reduced the 2006 gross margin by approximately $9.9 million; and

•

lower gains in trading and park and loan transactions due to a lower level of activity in Enogex’s marketing business and less favorable market conditions, which reduced the gross margin by approximately $6.0 million.

Park and loan transactions are planned or managed gas imbalances related to the marketing of natural gas.

Operating Income

Enogex’s consolidated operating income in 2006 was approximately $138.8 million, a $49.2 million increase from its consolidated operating income in 2005. The increase was attributable primarily to the $65.4 million increase described above in consolidated gross margin, as the aggregate of other operation and maintenance expenses, depreciation expense, impairment of assets and taxes other than income was only approximately $16.2 million higher during 2006 as compared to 2005. The variance in depreciation expense and in taxes other than income on a consolidated basis and by business segment was attributable primarily to new assets placed into service and slightly higher property taxes. The $13.4 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to:

•

higher salaries, wages and other employee benefits of approximately $12.7 million primarily due to higher incentive compensation and hiring additional employees to support business growth; and

•

higher materials and supplies costs of approximately $2.7 million primarily related to work performed to maintain the integrity and safety of Enogex’s pipelines, higher cost of materials and increased material used at newly added facilities.

These same factors were the primary reasons for the increases in other operation and maintenance expenses by segment.

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $8.3 million, or 25.2 percent, higher in 2006 as compared to 2005 primarily due to:

•

higher salaries, wages and other employee benefits expense of approximately $14.8 million primarily due to higher incentive compensation and hiring additional employees to support business growth;

•

decreased capitalized labor of approximately $3.2 million; and

•

higher materials and supplies expense of approximately $1.7 million.

These increases were partially offset by a change in 2006 in Enogex’s internal methods for allocating other operation and maintenance expenses, which lowered the allocations by OGE Energy to the transportation and storage business by approximately $10.3 million.

Other operation and maintenance expenses for the gathering and processing business were approximately $4.2 million, or 7.6 percent, higher in 2006 as compared to 2005 primarily due to:

•

an approximately $9.6 million increase resulting from the change in such allocation method; and

•

higher materials and supplies expense of approximately $1.0 million.

These increases were partially offset by:

•

lower salaries, wages and other employee benefits of approximately $5.7 million; and

•

a sales and use tax refund of approximately $2.0 million pertaining to activity in prior years.

Other operation and maintenance expenses for the marketing business were approximately $0.9 million, or 10.7 percent, higher in 2006 as compared to 2005 primarily due to a change in allocation methods of approximately $0.7 million and higher wages, salaries and other employee benefits of approximately $0.4 million.

Enogex Consolidated Information

Interest Income. Consolidated interest income was approximately $11.1 million in 2006 as compared to approximately $2.9 million in 2005, an increase of approximately $8.2 million primarily due to interest income earned on cash investments from the cash proceeds from the sale of Enogex Arkansas Pipeline Corporation (“EAPC”) in October 2005 and the sale of the Kinta Assets in May 2006.

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

•

a pre-tax litigation settlement of approximately $5.2 million in 2006;

•

a pre-tax gain of approximately $1.0 million in the fourth quarter of 2006 from the sale of certain west Texas pipeline assets; and

•

a pre-tax gain of approximately $0.5 million in the first quarter of 2006 from the sale of small gathering sections of Enogex’s pipeline.

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

Non-Recurring and Timing Items. For 2006, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “—Discontinued Operations,” was approximately $113.5 million, which included OERI’s recorded losses of approximately $6.3 million resulting from recording natural gas inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2007. Also, in 2006, Enogex had an increase in net income of approximately $41.2 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These increases in net income include:

•

an after-tax gain on the sale of the Kinta Assets in the second quarter of 2006 of approximately $34.1 million;

•

the approximately $3.2 million after-tax impact of a litigation settlement;

•

income from discontinued operations of approximately $1.9 million;

•

a sales and use tax refund related to activity in prior years of approximately $1.3 million after tax;

•

an after-tax gain of approximately $0.6 million related to the sale of certain west Texas pipeline assets; and

•

an after-tax gain of approximately $0.3 million from the sale of a small gathering section of Enogex’s pipeline.

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

For 2005, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “—Discontinued Operations,” was approximately $89.8 million, which included OERI’s recorded losses of approximately $1.2 million resulting from recording economic storage hedges at market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2006. Also, in 2005, Enogex had an increase in net income of approximately $45.3 million relating to various items that it does not consider to be reflective of the ongoing profitability of its business. These increases in net income include:

•

an after-tax gain on the sale of EAPC in October 2005 of approximately $36.7 million;

•

income from discontinued operations of approximately $11.3 million;

•

an after-tax gain on the sale of Enerven in August 2005 of approximately $1.8 million; and

•

income from a sales tax refund related to activity in prior years of approximately $0.2 million.

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

Enogex - Discontinued Operations

In May 2006, Enogex’s wholly owned subsidiary, Enogex Gas Gathering, L.L.C. (“Gathering”), sold the Kinta Assets, which included approximately 568 miles of gathering pipeline and 22 compressor units, for approximately $92.9 million. Enogex recorded an after tax gain of approximately $34.1 million from this sale in the second quarter of 2006.

In October 2005, Enogex sold its interest in EAPC, which held a 75 percent interest in the NOARK Pipeline System Limited Partnership, for approximately $177.4 million. Enogex recorded an after tax gain of approximately $36.7 million from this sale in the fourth quarter of 2005.

In August 2005, Enogex Compression Company, LLC (“Enogex Compression”) sold its interest in Enerven, a joint venture focused on the rental of natural gas compression assets, for approximately $7.3 million. Enogex Compression recognized an after tax gain of approximately $1.8 million from this sale in the third quarter of 2005.

The Consolidated Financial Statements of the Company have been reclassified to reflect the above sales as discontinued operations. Accordingly, revenues, costs and expenses and cash flows from these sales have been excluded from the respective captions in the Consolidated Financial Statements and have been separately reported as discontinued operations in the applicable financial statement captions. As the above sales occurred prior to 2007, there are no results of operations for discontinued operations during 2007. Results for these discontinued operations are summarized and discussed below.

Year Ended December 31 (In millions)	2007		2006		2005
Operating revenues	$	---	$	9.4	$	106.0
Cost of goods sold		---		4.9		69.5
Gross margin on revenues		---		4.5		36.5
Other operation and maintenance		---		1.0		7.5
Depreciation		---		0.3		5.8
Taxes other than income		---		0.1		1.3
Operating income		---		3.1		21.9
Interest income		---		---		0.2
Other income		---		56.0		66.2
Other expense		---		---		0.1
Interest expense		---		---		4.0
Income before taxes		---		59.1		84.2
Income tax expense		---		23.1		34.4
Net income	$	---	$	36.0	$	49.8

2007 compared to 2006. Following the sale of the Kinta Assets in May 2006, no operations of the Kinta Assets are reflected in the Consolidated Financial Statements.

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

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

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

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

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

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

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

Financial Condition

The balance of Cash and Cash Equivalents was approximately $8.8 million and $47.9 million at December 31, 2007 and 2006, respectively, a decrease of approximately $39.1 million, or 81.6 percent, primarily due to sales proceeds from the sale of the Kinta Assets in May 2006.

The balance of Funds on Deposit was approximately $32.0 million at December 31, 2006 with no balance at December 31, 2007. The decrease was due to an IRS settlement in November 2007 related to the Company’s change in method of accounting used to capitalize costs for self-constructed assets as discussed in Note 9 of Notes to Consolidated Financial Statements. The Funds on Deposit balance of approximately $32.0 million was applied against the Company’s consolidated income tax liability.

The balance of Fuel Inventories was approximately $82.0 million and $65.6 million at December 31, 2007 and 2006, respectively, an increase of approximately $16.4 million, or 25.0 percent, primarily due to outages at OG&E’s Sooner and Muskogee power plants during the third and fourth quarters of 2007, resulting in a higher coal inventory balance at December 31, 2007.

The balance of current Price Risk Management assets was approximately $7.7 million and $38.3 million at December 31, 2007 and 2006, respectively, a decrease of approximately $30.6 million, or 79.9 percent. The decrease was primarily due to OERI’s physical purchases and sales activity and corresponding economic hedges recorded at December 31, 2006 being realized during 2007 partially offset by new physical activity and corresponding economic hedges. The decrease was also related to transportation hedges recorded at December 31, 2006 being realized during 2007 partially offset by new Cheyenne Plains and other transportation hedges.

The balance of current Accumulated Deferred Tax Assets was approximately $38.1 million and $10.6 million at December 31, 2007 and 2006, respectively, an increase of approximately $27.5 million, primarily due to an increase in deferred hedging losses at Enogex.

The balance of Fuel Clause Under Recoveries was approximately $27.3 million at December 31, 2007 with no balance at December 31, 2006. This increase was due to the fact the amount billed to Oklahoma retail customers in 2007 was lower than 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 costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

The balance of Construction Work in Progress was approximately $179.8 million and $191.1 million at December 31, 2007 and 2006, respectively, a decrease of approximately $11.3 million, or 5.9 percent, primarily due to OG&E’s Centennial wind farm being placed in service during January 2007, partially offset by capital projects related to the December 2007 ice storm and various distribution and transmission projects at OG&E and transmission and gathering system projects at Enogex.

The balance of Regulatory Asset - SFAS 158 was approximately $174.6 million and $231.1 million at December 31, 2007 and 2006, respectively, a decrease of approximately $56.5 million, or 24.4 percent, primarily due to pension plan and restoration retirement plan settlement charges and a reduction in the Company’s plan obligations due to a better than expected return on plan assets, the Company’s contributions to the pension plan and a higher discount rate.

The balance of Other Deferred Charges and Other Assets was approximately $85.6 million and $23.1 million at December 31, 2007 and 2006, respectively, an increase of approximately $62.5 million, primarily due to deferred costs associated with the cancelled Red Rock power plant, deferred costs for storm activities and plan settlement charges which resulted in excess pension expense over the amount granted in rates by the OCC in OG&E’s most recent Oklahoma rate case.

The balance of Short-Term Debt was approximately $295.8 million at December 31, 2007 with no balance at December 31, 2006. The increase was primarily due to borrowings to fund OG&E’s Centennial wind farm, pension plan funding and daily operational needs of the Company.

The balance of Accounts Payable was approximately $399.3 million and $295.0 million at December 31, 2007 and 2006, respectively, an increase of approximately $104.3 million, or 35.4 percent, primarily due to accruals for the December 2007 ice storm, increased spending for capital and operating projects at Enogex and timing of outstanding checks clearing the bank.

The balance of Accrued Taxes was approximately $40.0 million and $57.0 million at December 31, 2007 and 2006, respectively, a decrease of approximately $17.0 million, or 29.8 percent, primarily due to a decrease in the Company’s estimated income tax liability.

The balance of current Price Risk Management liabilities was approximately $20.6 million and $5.6 million at December 31, 2007 and 2006, respectively, an increase of approximately $15.0 million, primarily due to decreased value of cash flow hedges of NGL sales and corresponding keep-whole natural gas purchases entered into during 2007 of approximately $43.9 million partially offset by collateral payments to the counterparties of approximately $28.5 million.

The balance of Fuel Clause Over Recoveries was approximately $4.2 million and $96.3 million at December 31, 2007 and 2006, respectively, a decrease of approximately $92.1 million, or 95.6 percent. The decrease was due to the fact that the amount billed to retail customers in Oklahoma and Arkansas in 2007 was lower than OG&E’s cost of fuel. The $4.2 million balance at December 31, 2007 represents the Arkansas fuel clause over recoveries as the Oklahoma portion was in a fuel clause under recovery position at December 31, 2007. 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 are intended to allow OG&E to amortize under or over recovery.

The balance of Accrued Benefit Obligations was approximately $156.2 million and $231.3 million at December 31, 2007 and 2006, respectively, a decrease of approximately $75.1 million, or 32.5 the percent, primarily due to pension plan contributions during 2007 and plan changes for prior service cost and net loss for the pension, restoration retirement and postretirement plans.

The balance of Accumulated Other Comprehensive Loss was approximately $81.0 million and $28.0 million at December 31, 2007, and 2006, respectively, an increase of approximately $53.0 million, primarily due to hedging losses at Enogex partially offset by plan changes for prior service cost and net loss for the pension, retirement restoration and postretirement plans.

Off-Balance Sheet Arrangements

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

Heat Pump Loans

In December 2002, OG&E sold approximately $8.5 million of its heat pump loans in a securitization transaction through OGE Consumer Loan 2002, LLC. In August 2007, OG&E repurchased the outstanding heat pump loan balance of approximately $0.6 million. There was no gain or loss associated with the repurchase of the heat pump loans.

OG&E Railcar Lease Agreement

OG&E leases more than 1,400 railcars used to deliver coal to OG&E’s coal-fired generation units. See Note 16 of Notes to Consolidated Financial Statements for a discussion of OG&E’s railcar lease agreement.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage, delays in recovering unconditional fuel purchase obligations and fuel clause under and over recoveries. The Company generally meets its cash needs through a combination of cash generated from operations, 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
		1 year	1 - 3 years	3 - 5 years	More than
(In millions)	Total	(2008)	(2009-2010)	(2011-2012)	5 years
OG&E capital expenditures including AFUDC (A)(B)	$3,808.8	$ 788.5	$ 842.9	$ 894.2	$ 1,283.2
Enogex capital expenditures including
capitalized interest	1,292.1	292.1	400.0	400.0	200.0
Other Operations capital expenditures	145.0	28.6	39.1	30.0	47.3
Total capital expenditures	5,245.9	1,109.2	1,282.0	1,324.2	1,530.5
Maturities of long-term debt	1,346.4	1.0	400.0	---	945.4
Interest payments on long-term debt	1,061.3	86.5	156.9	108.1	709.8
Pension funding obligations	103.0	50.0	27.0	26.0	N/A
Total capital requirements	7,756.6	1,246.7	1,865.9	1,458.3	3,185.7

Operating lease obligations
OG&E railcars	45.9	3.7	7.3	34.9	---
Enogex noncancellable operating leases	7.2	1.9	3.4	1.9	---
Total operating lease obligations	53.1	5.6	10.7	36.8	---

Other purchase obligations and commitments
OG&E cogeneration capacity payments	424.3	88.4	171.8	164.1	N/A
OG&E fuel minimum purchase commitments	428.5	115.1	224.5	69.3	19.6
Other	46.5	5.9	13.0	13.0	14.6
Total other purchase obligations and commitments	899.3	209.4	409.3	246.4	34.2

Total capital requirements, operating lease obligations
and other purchase obligations and commitments	8,709.0	1,461.7	2,285.9	1,741.5	3,219.9
Amounts recoverable through automatic fuel
adjustment clause (C)	(898.7)	(207.2)	(403.6)	(268.3)	(19.6)
Total, net	$7,810.3	$1,254.5	$ 1,882.3	$ 1,473.2	$ 3,200.3

(A) Under current environmental laws and regulations, OG&E may be required to spend approximately $470 million in capital expenditures on its power plants related to regional haze projects. These expenditures are expected to begin in 2008 and would continue over the next five years.

(B) Approximately $434.5 million of the 2008 capital expenditures are related to the proposed acquisition of the Redbud power plant.

(C) 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.

2007 Capital Requirements and Financing Activities

Total capital requirements, consisting of capital expenditures, maturities of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $676.5 million and contractual obligations, net of recoveries through automatic fuel adjustment clauses, were approximately $9.7 million resulting in total net capital requirements and contractual obligations of approximately $686.2 million in 2007. Approximately $9.3 million of the 2007 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $662.1 million and net contractual obligations of approximately $10.7 million totaling approximately $672.8 million in 2006, of which approximately $2.7 million was to comply with environmental regulations. During 2007, the Company’s sources of capital were internally generated funds from operating cash flows and short-term borrowings (through a combination of bank borrowings and commercial paper). The Company uses its commercial paper to fund changes in working capital and as an interim source of financing capital expenditures until permanent financing is arranged. Changes in working capital reflect the seasonal nature of the Company’s business, the revenue lag between billing and collection from customers and fuel inventories. See “Financial Condition” for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

Discontinued Operations

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

Additional asset sales could further contribute to the Company’s liquidity.

Long-Term Debt Maturities

Maturities of the Company’s long-term debt during the next five years consist of $1.0 million in 2008 and $400.0 million in 2010. There are no maturities of the Company’s long-term debt in years 2009, 2011 or 2012.

Cash Flows

Year Ended December 31(In millions)	2007	2006	2005
Net cash provided from operating activities	$ 328.5	$ 569.5	$ 437.9
Net cash used in investing activities	(556.3)	(483.5)	(291.3)
Net cash provided from (used in) financing activities	188.7	(137.4)	(234.6)

The reduction of approximately $241.0 million in net cash provided from operating activities in 2007 as compared to 2006 primarily related to lower fuel recoveries from OG&E customers partially offset by changes to other working capital. The increase of approximately $131.6 million in net cash provided from operating activities in 2006 as compared to 2005 primarily related to higher fuel clause recoveries from OG&E customers and a higher level of net income partially offset by changes to price risk management assets and liabilities and changes in working capital.

The increase of approximately $72.8 million in net cash used in investing activities in 2007 as compared to 2006 related to higher levels of capital expenditures. The increase of approximately $192.2 million in net cash used in investing activities in 2006 as compared to 2005 related to higher levels of capital expenditures.

The increase of approximately $326.1 million in net cash provided from financing activities in 2007 as compared to 2006 primarily related to higher levels of short-term debt partially offset by reduced amounts related to the issuance of long-term debt. The reduction of approximately $97.2 million in net cash used in financing activities in 2006 as compared to 2005 primarily related to proceeds from the issuance of long-term debt and maturities of long-term debt partially offset by lower levels of short-term debt.

Future Capital Requirements

Capital Expenditures

The Company’s current 2008 to 2013 construction program includes continued investment in OG&E’s distribution, generation and transmission system and Enogex’s transportation, storage, gathering and processing assets. The Company’s current estimates of capital expenditures are approximately: 2008 - $1.1 billion (approximately $434.5 million are related to the proposed acquisition of the Redbud power plant), 2009 - $613.9 million, 2010 - $668.1 million, 2011 - $653.4 million, 2012 - $670.8 million and 2013 - $654.1 million. OG&E also has approximately 430 MWs of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

Pension and Postretirement Benefit Plans

All eligible employees of the Company and participating affiliates are covered by a non-contributory defined benefit pension plan. During 2007, actual asset returns for the Company’s defined benefit pension plan were positively affected by growth in the equity markets. At December 31, 2007, approximately 61 percent of the pension plan assets were invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2007, asset returns on the pension plan were approximately 4.4 percent as compared to approximately 14.5 percent in 2006. 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 decreased from approximately $90.0 million in 2006 to approximately $50.0 million in 2007. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2008, the Company may contribute up to $50.0 million to its pension plan.

In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation or the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007 and 2006, the Company experienced an increase in both the number of employees electing to retire and the amount of lump-sum payments to be paid to such employees upon retirement as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, the Company recorded pension settlement charges in 2007 and 2006 and a retirement restoration plan settlement charge in 2007. The pension settlement charges and retirement restoration plan settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense or retirement restoration expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions)	OG&E (A)	Enogex	OGE Energy	Total

Pension Settlement Charges:
2007	$ 13.3	$ 0.5	$ 2.9	$ 16.7

2006	$ 13.3	$ 0.8	$ 3.0	$ 17.1

Retirement Restoration Plan Settlement Charge:
2007	$ 0.1	$ ---	$ 2.2	$ 2.3

(A) OG&E’s Oklahoma jurisdictional portion of these charges were recorded as a regulatory asset (see Note 1 of Notes to Consolidated Financial Statements for a further discussion).

As discussed in Note 14 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 on or after February 1, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, the Company’s cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees

included in the cash balance plan feature increases, the Company’s cash requirements should decrease and will be much less sensitive to changes in discount rates.

At December 31, 2007, the projected benefit obligation and fair value of assets of the Company’s pension plan and restoration of retirement income plan was approximately $522.0 million and $514.2 million, respectively, for an underfunded status of approximately $7.8 million. Also, at December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s postretirement benefit plans was approximately $216.8 million and $78.5 million, respectively, for an underfunded status of approximately $138.3 million. The above amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E’s portion which is recorded as a regulatory asset as discussed in Note 1 of Notes to Consolidated Financial Statements) in the Company’s Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss and as a regulatory asset represent a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.

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

Pension Plan Costs and Assumptions

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants.

Many of the changes enacted as part of the Pension Protection Act are required to be implemented as of the first plan year beginning in 2008. While the Company generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. The Company is taking steps now to ensure that its plans, as well as participants and outside administrators, are aware of the changes. In some instances, changes will necessitate notices to participants and/or changes in the plan’s administrative forms.

Optional Redemption of Long-Term Debt

OG&E’s $125.0 million principal amount 6.65 percent Senior Notes (“Senior Notes”) due July 15, 2027, included a one-time option of the holders to redeem the notes on July 15, 2007, at 100 percent of the principal amount with accrued and unpaid interest. In July 2007, $50,000 of the Senior Notes were redeemed by the holders and retired.

Adoption of FIN No. 48

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of self-constructed assets discussed in Note 9 of Notes to Consolidated Financial Statements. On November 27, 2007, OG&E reached a final settlement with the IRS related to the tax method of accounting, which resulted in the reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position.

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	P2	A2	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, commodity prices, levels of drilling activity, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

Future Sources of Financing

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

Issuance of New Long-Term Debt

In January 2008, OG&E issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings.

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. At December 31, 2007, the Company had approximately $295.0 million in outstanding commercial paper borrowings. Also, OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2007 and ending December 31, 2008.

In December 2006, the Company and OG&E amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for the Company and $400 million for OG&E. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods. In November 2007, the Company and OG&E utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at the end of the two renewal options to convert the outstanding balance to a one-year term loan. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

It is currently expected that Enogex will enter into a $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes during the first quarter of 2008.

Future Financings Under Carbon Principles

In February 2008, three of the largest global financial institutions presented a set of principles (“Carbon Principles”) for meeting energy needs in the U.S. that they said balance cost, reliability and greenhouse gas concerns. These Carbon Principles focus on a portfolio approach that includes efficiency, renewable and low carbon power sources, as well as centralized generation sources in light of concerns regarding the impact of greenhouse gas emissions while recognizing the need to provide reliable power at a reasonable cost to consumers. According to financial institutions advocating the Carbon Principles, they are intended to create an industry best practice for the evaluation of options to meet the electric power needs of the U.S. in an environmentally responsible and cost effective manner. Some of the key points of the Carbon Principles are:

•

Encourage clients to pursue cost-effective energy efficiency taking into consideration the potential value of avoided carbon dioxide emissions;

•

Encourage clients to invest in cost-effective renewables and distributed energy technologies; and

•

Educate clients, regulators and other industry participants regarding the additional diligence required for fossil fuel generation financings and encourage regulatory and legislative changes that facilitate carbon capture and storage to reduce carbon dioxide emissions.

The advocates of the Carbon Principles would apply an enhanced diligence process to financings for companies that have announced plans to construct fossil fuel generation plants in the U.S. of over 200 MWs. The adoption of these Carbon Principles could negatively affect OG&E’s ability to obtain financing in the future related to coal generation or expansion of capacity.

Common Stock

See Note 10 of Notes to Consolidated Financial Statements for a discussion of the Company’s common stock activity.

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 effect on the Company’s Consolidated Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s Audit Committee.

Consolidated (including all Company segments)

Pension and Postretirement Benefit Plans

The Company has defined benefit retirement and postretirement plans that cover substantially all of the Company’s employees. 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 14 of Notes to Consolidated Financial Statements. The assumed return on plan assets is based on management’s expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the pension plan. The following table indicates the sensitivity of the pension plan funded status to these variables.

		Impact on
	Change	Funded Status
Actual plan asset returns	+/- 5 percent	+/- $25.7 million
Discount rate	+/- 0.25 percent	+/- $16.9 million
Contributions	+ $10.0 million	+ $10.0 million
Expected long-term return on plan assets	+/- 1 percent	None

Impairment of Assets

The Company assesses potential impairments of assets or asset groups when there is evidence that events or changes in circumstances require an analysis of the recoverability of an asset or asset group. For purposes of recognition and measurement of an impairment loss, a long-lived asset or assets shall be grouped with other assets and liabilities at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future cash flows used to test the recoverability of a long-lived asset or asset group shall include only the future cash flows (cash inflows less associated cash outflows) that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the asset or asset group. The fair value of these assets is based on third-party evaluations, prices for similar assets, historical data and projected cash flows. 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 Company had no material impairments during 2007, 2006 or 2005.

Commitments and Contingencies

Except as otherwise disclosed in this Annual Report on Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. See Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 in this Annual Report on Form 10-K.

Asset Retirement Obligations

In accordance with FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” an entity was required to recognize a liability for the fair value of an asset retirement obligation (“ARO”) that was conditional on a future event if the liability’s fair value could be reasonably estimated. The fair value of a liability for the conditional ARO was recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO was factored into the measurement of the liability when sufficient information existed. However, in some cases, there was insufficient information to estimate the fair value of an ARO. In these cases, the liability was initially recognized in the period in which sufficient information was available for an entity to make a reasonable estimate of the liability’s fair value. The Company did not recognize any new AROs during 2007; however, the Company has identified certain AROs that have not been recorded because the Company determined that these assets, primarily related to Enogex’s processing plants and compression sites, have indefinite lives.

Hedging Policies

Enogex engages in cash flow hedge transactions to manage commodity risk. Enogex may hedge its forward exposure to manage the impact of changes in commodity prices. Hedges of anticipated transactions are documented as cash flow hedges pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and are executed based upon management-established price targets. During 2005, Enogex utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas and certain types of NGL hedges. During 2006, Enogex utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas, NGL hedges and certain transportation hedges. During 2007, Enogex utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas, NGL hedges and certain transportation and natural gas inventory hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. OG&E and Enogex engage in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2005, 2006 and 2007, OG&E entered into treasury lock agreements relating to managing interest rate exposure on the debt portfolio or anticipated debt issuances to modify the interest rate exposure on fixed rate debt issues. The treasury lock agreements in

2005 and 2006 qualified as cash flow hedges under SFAS No. 133. The objective of these treasury lock agreements was to protect against the variability of future interest payments of long-term debt that was issued by OG&E.

Electric Utility Segment

Regulatory Assets and Liabilities

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

OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The Company adopted certain provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which required the Company to separately disclose the items that had not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. OG&E met both criteria and, therefore, recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

Unbilled Revenues

OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. At December 31, 2007, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of approximately $0.2 million. At December 31, 2007 and 2006, Accrued Unbilled Revenues were approximately $45.7 million and $39.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. At December 31, 2007, 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 $3.4 million and $3.3 million at December 31, 2007 and 2006, respectively.

Natural Gas Transportation and Storage, Gathering and Processing and Marketing Segments

Operating Revenues

Operating revenues associated with the production of NGLs 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.

Natural Gas Purchases

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

Energy Purchase and Sale Contracts

The Company’s activities include the marketing and hedging of natural gas and NGLs. 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 presented at fair value in Price Risk Management Assets, Price Risk Management Liabilities or against the brokerage deposits in Other Current Assets on the Consolidated Balance Sheets. The offsetting gains and losses from changes in the fair value are recognized in earnings or, for transactions designated and qualifying as cash flow hedges according to SFAS No. 133, are presented in Other Comprehensive Income. Recognized gains and losses on energy contracts are presented in Operating Revenues on the Consolidated Statements of Income.

In nearly all cases, independent market prices are obtained and compared to the values used in determining the fair value, 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 of transactions not designated as cash flow hedges is subject to mark-to-market risk loss limitations provided under the Company’s risk policies. Management utilizes models to estimate the fair value of the Company’s energy contracts including derivatives that do not have an independent market price. At December 31, 2007, unrealized mark-to-market losses were approximately $0.9 million, which included approximately $0.3 million of unrealized mark-to-market losses that were calculated utilizing models. At December 31, 2007, a price movement of one percent for prices verified by independent parties would result in unrealized mark-to-market gains or losses of less than $0.1 million and a price movement of five percent on model-based prices would result in unrealized mark-to-market gains or losses of approximately $0.1 million.

Natural Gas Inventory

Natural gas inventory is held by Enogex, through its transportation and storage business, and by OERI. The transportation and storage business maintains natural gas inventory to provide operational support for its pipeline deliveries. In addition, as part of its recurring buy and sell activity, OERI injects and withdraws natural gas into and out of inventory under the terms of its storage capacity contracts. In an effort to mitigate market price exposures, both businesses enter into contracts or hedging instruments to protect the cash flows associated with their inventory. During 2005, 2006 and 2007, OERI elected not to designate inventory hedging contracts as fair value or cash flow hedges under SFAS No. 133. The fair value of the hedging instruments is recorded on the books of OERI as Price Risk Management Assets, Price Risk Management Liabilities or against the brokerage deposits in Other Current Assets with an offsetting gain or loss recorded in current earnings. All natural gas inventory held by Enogex is recorded at the lower of cost or market. During 2007 and 2006, Enogex recorded write-downs to market value related to natural gas storage inventory of approximately $3.6 million and $18.7 million, respectively. The amount of Enogex’s natural gas inventory was approximately $37.7 million and $35.9 million at December 31, 2007 and 2006, respectively. Natural gas storage inventory is presented in Fuel Inventories on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

Allowance for Uncollectible Accounts Receivable

The allowance for uncollectible accounts receivable is calculated based on outstanding accounts receivable balances over 180 days old. In addition, other outstanding accounts receivable balances less than 180 days old are reserved on a case-by-case basis when the Company believes the collection 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 aggregate allowance for uncollectible accounts receivable for the transportation and storage, gathering and processing and marketing segments was approximately $0.4 million and $1.1 million at December 31, 2007 and 2006, respectively.

Accounting Pronouncements

See Notes 1, 3, 4, 6, 9 and 14 of Notes to Consolidated Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

Electric Competition; Regulation

OG&E and Enogex have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas were postponed in 2001, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on the Company due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring also could have a significant impact on the Company’s consolidated financial position, results of operations and cash flows. The Company cannot predict when it will be subject to changes in legislation or regulation, nor can it predict the impact of these changes on the Company’s consolidated financial position, results of operations or cash flows. The Company believes that the prices for electricity and the quality and reliability of the Company’s service currently place us in a position to compete effectively in the energy market. OG&E is also subject to competition in various degrees from state-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. OG&E has a franchise to serve in more than 270 towns and cities throughout its service territory.

Commitments and Contingencies

Except as disclosed otherwise in this Annual Report on Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. See Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I in this Annual Report on Form 10-K for a discussion of the Company’s commitments and contingencies.

Quantitative and Qualitative Disclosures About Market Risk.

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

Risk Committee and Oversight

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

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

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

Risk Policies

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

The Company’s price risk management assets and liabilities as of December 31, 2007 were as follows:

		Notional Value
	Commodity	(MMBtu)	Maturity	Fair Value
	(dollars in millions)
Trading
Price Risk Management Assets
Physical Purchases	Natural Gas	7.3	2008	$ 0.2
Physical Sales	Natural Gas	29.6	2008	5.0
Short Physical Options	Natural Gas	27.1	2008	0.9
Long Basis Positions	Natural Gas	13.4	2008	2.9
Long Basis Positions	Natural Gas	0.9	2009	0.2
Total Long Basis Positions				3.1
Short Basis Positions	Natural Gas	3.6	2008	0.3
Total Trading Price Risk Management Assets				$ 9.5
Non-Trading
Long Financial Swaps/Futures (exclude Basis)	Natural Gas	0.7	2008	$ 0.2
Short Financial Swaps/Futures (exclude Basis)	Natural Gas	1.2	2008	0.4
Long Financial Options	Natural Gas Liquids	1.3	2008	0.2
Long Financial Options	Natural Gas Liquids	1.3	2009	0.8
Long Financial Options	Natural Gas Liquids	1.3	2010	1.4
Total Long Financial Options				2.4
Total Non-Trading Price Risk Management Assets				$ 3.0
Total Price Risk Management Assets				$ 12.5
Amounts offset in Price Risk Management through
Master Netting Agreements				(4.5)
Net Price Risk Management Assets				$ 8.0
Trading
Price Risk Management Liabilities
Physical Purchases	Natural Gas	22.1	2008	$ 1.1
Physical Sales	Natural Gas	12.1	2008	0.6
Long Physical Options	Natural Gas	2.7	2008	0.5
Long Financial Swaps/Futures (exclude Basis)	Natural Gas	0.2	2008	0.1
Long Basis Positions	Natural Gas	5.5	2008	0.6
Short Basis Positions	Natural Gas	12.9	2008	2.1
Short Basis Positions	Natural Gas	0.9	2009	0.3
Total Short Basis Positions				2.4
Total Trading Price Risk Management Liabilities				$ 5.3
Non-Trading
Long Financial Swaps/Futures (exclude Basis)	Natural Gas	11.8	2008	$ 10.9
Long Financial Swaps/Futures (exclude Basis)	Natural Gas	10.5	2009	4.4
Long Financial Swaps/Futures (exclude Basis)	Natural Gas	9.8	2010	0.4
Total Long Financial Swaps/Futures (exclude Basis)				15.7
Short Financial Swaps/Futures (exclude Basis)	Natural Gas Liquids	2.5	2008	33.9
Short Financial Swaps/Futures (exclude Basis)	Natural Gas Liquids	1.3	2009	18.8
Short Financial Swaps/Futures (exclude Basis)	Natural Gas Liquids	1.3	2010	14.9
Total Short Financial Swaps/Futures (exclude Basis)				67.6
Treasury Lock Agreements	Interest Rates		2008	1.7
Total Non-Trading Price Risk Management Liabilities				$ 85.0
Total Price Risk Management Liabilities				$ 90.3
Amounts offset in Price Risk Management through
Master Netting Agreements				(58.4)
Net Price Risk Management Liabilities				$ 31.9

The valuation of the Company’s price risk management assets and liabilities were determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties.

Interest Rate Risk

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

OG&E entered into two separate treasury lock agreements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008 in conjunction with the issuance of long-term debt by OG&E.

The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities. At December 31, 2007, the Company had no outstanding interest rate swap agreements. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.

Year ended December 31								12/31/07
(Dollars in millions)	2008	2009	2010	2011	2012	Thereafter	Total	Fair Value
Fixed-rate debt (A)
Principal amount	$ 1.0	$ ---	$ 400.0	$ ---	$ ---	$ 810.0	$ 1,211.0	$ 1,262.2
Weighted-average
interest rate	7.07%	---	8.13%	---	---	6.05%	6.74%	---
Variable-rate debt (B)
Principal amount	---	---	---	---	---	$ 135.4	$ 135.4	$ 135.4
Weighted-average
interest rate	---	---	---	---	---	3.70%	3.70%	---

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

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

Commodity Price Risk

The market risks inherent in 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.

Trading Activities

The trading activities are conducted throughout the year subject to daily and monthly trading stop loss limits set by the Risk Oversight Committee. Those trading stop loss limits currently are $2.5 million. The daily loss exposure from trading activities is measured primarily using VaR, which estimates the potential losses the trading activities could incur over a specified time horizon and confidence level. The VaR limit set by the Risk Oversight Committee for the Company’s trading activities, assuming a 95 percent confidence level, currently is $1.5 million. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company’s operating income.

A sensitivity analysis has been prepared to estimate the Company’s exposure to market risk created by trading activities. The value of trading positions is a summation of the fair values calculated for each net commodity position based upon quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in quoted market prices over the next 12 months. The result of this analysis, which may differ from actual results, is as follows at December 31, 2007.

(In millions)	Trading

Commodity market risk, net	$ 0.1

Non-Trading Activities

The prices of natural gas, NGLs and NGL processing spreads are subject to fluctuations resulting from changes in supply and demand. The changes in these prices have a direct effect on the compensation the Company receives for operating some of its assets. To partially reduce non-trading commodity price risk, the Company hedges, through the utilization of derivatives and other forward transactions, the effects these market fluctuations have on the Company’s operating income. 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.

A sensitivity analysis has been prepared to estimate the Company’s exposure to the market risk of the Company’s 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. Quoted market prices are not available for all of the Company’s non-trading positions, therefore, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forward price curves. 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 result of this analysis, which may differ from actual results, is as follows at December 31, 2007.

(In millions)	Non-Trading

Commodity market risk, net	$ 17.7

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133. Normal purchases and normal sales contracts are not recorded in Price Risk Management assets or liabilities in the Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales to (i) commodity contracts for the purchase and sale of natural gas; (ii) commodity contracts for the sale of NGLs produced by its subsidiary, Enogex Products Corporation; (iii) electric power contracts by OG&E; and (iv) fuel procurement by OG&E.

Credit Risk

Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.

For OG&E, new business customers are required to provide a security deposit in the form of cash, a bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, 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 position (including credit rating, if available), 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 position of existing counterparties on an ongoing basis.

Financial Statements and Supplementary Data.

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

Year ended December 31 (In millions, except per share data)	2007	2006	2005
OPERATING REVENUES
Electric Utility operating revenues	$ 1,835.1	$ 1,745.7	$ 1,720.7
Natural Gas Pipeline operating revenues	1,962.5	2,259.9	4,190.8
Total operating revenues	3,797.6	4,005.6	5,911.5
COST OF GOODS SOLD (exclusive of depreciation shown below)
Electric Utility cost of goods sold	977.8	902.5	946.6
Natural Gas Pipeline cost of goods sold	1,656.9	2,000.0	3,995.7
Total cost of goods sold	2,634.7	2,902.5	4,942.3
Gross margin on revenues	1,162.9	1,103.1	969.2
Other operation and maintenance	436.8	416.6	394.9
Depreciation	195.3	181.4	182.6
Impairment of assets	0.5	0.3	---
Taxes other than income	75.0	72.1	69.3
OPERATING INCOME	455.3	432.7	322.4
OTHER INCOME (EXPENSE)
Interest income	2.1	6.2	3.5
Allowance for equity funds used during construction	---	4.1	---
Other income (loss)	17.4	16.3	(0.3)
Other expense	(23.7)	(16.7)	(5.5)
Net other income (expense)	(4.2)	9.9	(2.3)
INTEREST EXPENSE
Interest on long-term debt	87.8	87.4	80.0
Allowance for borrowed funds used during construction	(4.0)	(4.5)	(2.2)
Interest on short-term debt and other interest charges	6.4	13.1	12.5
Interest expense	90.2	96.0	90.3
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	360.9	346.6	229.8
INCOME TAX EXPENSE	116.7	120.5	68.6
INCOME FROM CONTINUING OPERATIONS	244.2	226.1	161.2
DISCONTINUED OPERATIONS (NOTE 7)
Income from discontinued operations	---	59.1	84.2
Income tax expense	---	23.1	34.4
Income from discontinued operations	---	36.0	49.8
NET INCOME	$ 244.2	$ 262.1	$ 211.0

BASIC AVERAGE COMMON SHARES OUTSTANDING	91.7	91.0	90.3
DILUTED AVERAGE COMMON SHARES OUTSTANDING	92.5	92.1	90.8
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations	$ 2.66	$ 2.48	$ 1.79
Income from discontinued operations, net of tax	---	0.40	0.55
NET INCOME	$ 2.66	$ 2.88	$ 2.34
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations	$ 2.64	$ 2.45	$ 1.77
Income from discontinued operations, net of tax	---	0.39	0.55
NET INCOME	$ 2.64	$ 2.84	$ 2.32
DIVIDENDS DECLARED PER SHARE	$ 1.3675	$ 1.3375	$ 1.33

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

December 31 (In millions)	2007	2006

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$ 8.8	$ 47.9
Funds on deposit	---	32.0
Accounts receivable, less reserve of $3.8 and $4.4, respectively	334.4	344.3
Accrued unbilled revenues	45.7	39.7
Fuel inventories	82.0	65.6
Materials and supplies, at average cost	63.6	58.7
Price risk management	7.7	38.3
Gas imbalances	6.7	2.8
Accumulated deferred tax assets	38.1	10.6
Fuel clause under recoveries	27.3	---
Prepayments	8.0	9.0
Other	7.2	11.6
Total current assets	629.5	660.5

OTHER PROPERTY AND INVESTMENTS, at cost	44.5	35.2

PROPERTY, PLANT AND EQUIPMENT
In service	6,809.2	6,307.7
Construction work in progress	179.8	191.1
Total property, plant and equipment	6,989.0	6,498.8
Less accumulated depreciation	2,742.7	2,631.3
Net property, plant and equipment	4,246.3	3,867.5

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net	17.4	31.1
Regulatory asset - SFAS 158	174.6	231.1
Price risk management	0.3	1.7
McClain Plant deferred expenses	12.4	18.7
Unamortized loss on reacquired debt	18.9	20.1
Unamortized debt issuance costs	8.3	9.4
Other	85.6	23.1
Total deferred charges and other assets	317.5	335.2

TOTAL ASSETS	$ 5,237.8	$ 4,898.4

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS (Continued)

December 31 (In millions)	2007	2006

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$ 295.8	$ ---
Accounts payable	399.3	295.0
Dividends payable	31.9	31.1
Customer deposits	55.5	53.4
Accrued taxes	40.0	57.0
Accrued interest	37.0	37.7
Accrued compensation	53.9	46.0
Long-term debt due within one year	1.0	3.0
Price risk management	20.6	5.6
Gas imbalances	11.1	11.1
Fuel clause over recoveries	4.2	96.3
Other	38.2	33.2
Total current liabilities	988.5	669.4

LONG-TERM DEBT	1,344.6	1,346.3

COMMITMENTS AND CONTINGENCIES (NOTE 16)

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	156.2	231.3
Accumulated deferred income taxes	853.6	859.2
Accumulated deferred investment tax credits	22.0	26.8
Accrued removal obligations, net	139.7	125.5
Price risk management	11.3	1.1
Other	41.0	35.0
Total deferred credits and other liabilities	1,223.8	1,278.9

STOCKHOLDERS’ EQUITY
Common stockholders’ equity	756.2	741.0
Retained earnings	1,005.7	890.8
Accumulated other comprehensive loss, net of tax	(81.0)	(28.0)
Total stockholders’ equity	1,680.9	1,603.8

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 5,237.8	$ 4,898.4

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31 (In millions)			2007	2006

STOCKHOLDERS’ EQUITY
Common stock, par value $0.01 per share; authorized 125.0 shares;
and outstanding 91.8 and 91.2 shares, respectively			$ 0.9	$ 0.9
Premium on capital stock			755.3	740.1
Retained earnings			1,005.7	890.8
Accumulated other comprehensive loss, net of tax			(81.0)	(28.0)
Total stockholders’ equity			1,680.9	1,603.8

LONG-TERM DEBT
SERIES		DATE DUE
Senior Notes - OGE Energy Corp.
5.00 %	Senior Notes, Series Due November 15, 2014		100.0	100.0
Unamortized discount			(0.6)	(0.7)

Senior Notes - OG&E
5.15 %	Senior Notes, Series Due January 15, 2016		110.0	110.0
6.50 %	Senior Notes, Series Due July 15, 2017		125.0	125.0
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	140.0
5.75 %	Senior Notes, Series Due January 15, 2036		110.0	110.0
Other Bonds - OG&E
3.25% - 4.07% Garfield Industrial Authority, January 1, 2025			47.0	47.0
3.24% - 4.03% Muskogee Industrial Authority, January 1, 2025			32.4	32.4
3.35% - 4.11% Muskogee Industrial Authority, June 1, 2027			56.0	56.0

Unamortized discount			(2.0)	(2.1)

Enogex Notes
8.28%	Medium-Term Notes, Series Due 2007		---	3.0
7.07%	Medium-Term Notes, Series Due 2008		1.0	1.0
8.125%	Medium-Term Notes, Series Due 2010		400.0	400.0

Unamortized swap monetization			1.8	2.7
Total long-term debt			1,345.6	1,349.3
Less long-term debt due within one year			1.0	3.0
Total long-term debt (excluding long-term debt due within one year)			1,344.6	1,346.3

Total Capitalization			$ 3,025.5	$ 2,950.1

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

		Premium		Accumulated
		on		Other
	Common	Capital	Retained	Comprehensive
(In millions)	Stock	Stock	Earnings	Income (Loss)	Total
Balance at December 31, 2004	$ 0.9	$ 699.9	$ 659.8	$ (75.0)	$ 1,285.6
Comprehensive income
Net income for 2005	---	---	211.0	---	211.0
Other comprehensive income, net of tax
Minimum pension liability adjustment (($30.0) pre-tax)	---	---	---	(18.4)	(18.4)
Deferred hedging gains ($4.7 pre-tax)	---	---	---	2.9	2.9
Amortization of cash flow hedge ($0.5 pre-tax)	---	---	---	0.3	0.3
Other comprehensive loss	---	---	---	(15.2)	(15.2)
Comprehensive income	---	---	211.0	(15.2)	195.8
Dividends declared on common stock	---	---	(120.3)	---	(120.3)
Issuance of common stock	---	14.7	---	---	14.7
Balance at December 31, 2005	0.9	714.6	750.5	(90.2)	1,375.8
Comprehensive income
Net income for 2006	---	---	262.1	---	262.1
Other comprehensive income, net of tax
Minimum pension liability adjustment ($147.5 pre-tax)	---	---	---	90.4	90.4
Minimum pension liability adjustment - SFAS No. 158
($1.1 pre-tax)	---	---	---	0.7	0.7
Deferred hedging gains ($4.1 pre-tax)	---	---	---	2.5	2.5
Amortization of cash flow hedge ($0.5 pre-tax)	---	---	---	0.3	0.3
Other comprehensive income	---	---	---	93.9	93.9
Comprehensive income	---	---	262.1	93.9	356.0
Adjustment to initially apply SFAS 158, net of tax
Defined benefit pension plan:
Net loss, net of tax (($33.9) pre-tax)	---	---	---	(20.7)	(20.7)
Prior service cost, net of tax (($6.6) pre-tax)	---	---	---	(4.1)	(4.1)
Defined benefit postretirement plans:
Net loss, net of tax (($11.7) pre-tax)	---	---	---	(5.4)	(5.4)
Net transition obligation, net of tax (($1.2) pre-tax)	---	---	---	(0.8)	(0.8)
Prior service cost, net of tax (($1.2) pre-tax)	---	---	---	(0.7)	(0.7)
Adj. to initially apply SFAS 158, net of tax	---	---	---	(31.7)	(31.7)
Dividends declared on common stock	---	---	(121.8)	---	(121.8)
Issuance of common stock	---	25.5	---	---	25.5
Balance at December 31, 2006	0.9	740.1	890.8	(28.0)	1,603.8
Comprehensive income
Net income for 2007	---	---	244.2	---	244.2
Other comprehensive income, net of tax
Defined benefit pension plan:
Net loss, net of tax ($4.4 pre-tax)	---	---	---	2.7	2.7
Prior service cost, net of tax ($5.4 pre-tax)	---	---	---	3.3	3.3
Defined benefit postretirement plans:
Net loss, net of tax ($3.3 pre-tax)	---	---	---	1.7	1.7
Net transition obligation, net of tax ($0.2 pre-tax)	---	---	---	0.1	0.1
Prior service cost, net of tax ($0.5 pre-tax)	---	---	---	0.3	0.3
Deferred hedging gains (losses) (($100.0) pre-tax)	---	---	---	(61.3)	(61.3)
Amortization of cash flow hedge ($0.4 pre-tax)	---	---	---	0.2	0.2
Other comprehensive loss	---	---	---	(53.0)	(53.0)
Comprehensive income	---	---	244.2	(53.0)	191.2
Dividends declared on common stock	---	---	(125.5)	---	(125.5)
FIN No. 48 adoption (($6.2) pre-tax)	---	---	(3.8)	---	(3.8)
Issuance of common stock	---	15.2	---	---	15.2
Balance at December 31, 2007	$ 0.9	$ 755.3	$ 1,005.7	$ (81.0)	$ 1,680.9

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)	2007	2006	2005
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations	$ 244.2	$ 226.1	$ 161.2
Adjustments to reconcile income from continuing operations to net cash provided from operating activities
Minority interest income	1.0	---	---
Depreciation	195.3	181.4	182.6
Impairment of assets	0.5	0.3	---
Deferred income taxes and investment tax credits, net	16.1	32.3	21.9
Allowance for equity funds used during construction	---	(4.1)	---
(Gain) loss on sale of assets	(0.1)	(1.6)	0.1
Loss on retirement and abandonment of assets	3.8	6.0	---
Stock-based compensation expense	3.6	3.8	0.9
Excess tax benefit on stock-based compensation	(2.8)	(1.4)	---
Price risk management assets	32.0	58.2	(62.6)
Price risk management liabilities	(74.3)	(83.5)	80.1
Other assets	(24.8)	(73.7)	(6.4)
Other liabilities	(61.5)	18.1	(2.9)
Change in certain current assets and liabilities
Funds on deposit	32.0	(32.0)	---
Accounts receivable, net	9.9	247.1	(106.9)
Accrued unbilled revenues	(6.0)	2.1	3.7
Fuel, materials and supplies inventories	(21.3)	(4.4)	22.1
Gas imbalance asset	(3.9)	29.2	67.8
Fuel clause under recoveries	(27.3)	101.1	(46.8)
Other current assets	5.4	9.3	12.4
Accounts payable	104.3	(215.4)	40.1
Customer deposits	2.1	5.6	(0.5)
Accrued taxes	(13.5)	(7.2)	53.9
Accrued interest	(7.0)	5.8	(0.9)
Accrued compensation	7.9	5.7	2.9
Gas imbalance liability	---	(24.9)	19.7
Fuel clause over recoveries	(92.1)	96.3	---
Other current liabilities	5.0	(10.7)	(4.5)
Net Cash Provided from Operating Activities	328.5	569.5	437.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(557.7)	(486.6)	(297.2)
Proceeds from sale of assets	1.4	3.2	5.8
Other investing activities	---	(0.1)	0.1
Net Cash Used in Investing Activities	(556.3)	(483.5)	(291.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	---	217.5	---
Retirement of long-term debt	(3.1)	---	(254.3)
Increase (decrease) in short-term debt, net	295.8	(250.0)	125.0
Issuance of common stock	8.2	14.5	14.7
Excess tax benefit on stock-based compensation	2.8	1.4	---
Contributions from partners	9.7	---	---
Dividends paid on common stock	(124.7)	(120.8)	(120.0)
Net Cash Provided From (Used in) Financing Activities	188.7	(137.4)	(234.6)
DISCONTINUED OPERATIONS
Net cash used in operating activities	---	(19.9)	(43.0)
Net cash provided from investing activities	---	92.8	146.4
Net cash used in financing activities	---	---	(0.1)
Net Cash Provided from Discontinued Operations	---	72.9	103.3
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(39.1)	21.5	15.3
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	47.9	26.4	11.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 8.8	$ 47.9	$ 26.4

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

Enogex Inc. and its subsidiaries (“Enogex”) are a provider of integrated natural gas midstream services. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing. Historically, Enogex had also engaged in natural gas marketing through its subsidiary, OGE Energy Resources, Inc. (“OERI”). In connection with the proposed initial public offering of common units of OGE Enogex Partners L.P., a Delaware limited partnership (the “Partnership”), discussed in Note 2, on January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Enogex’s historical consolidated financial statements were prepared from Enogex’s books and records related to Enogex’s operating assets. Accordingly, the discussion that follows includes the results of OERI, but as of January 1, 2008, Enogex no longer has any interest in the results of OERI.

The Company allocates operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. The Company adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. 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.

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

December 31(In millions)	2007	2006
Regulatory Assets
Regulatory asset - SFAS 158	$ 174.6	$ 231.1
Deferred storm expenses	35.9	---
Fuel clause under recoveries	27.3	---
Deferred pension plan expenses	24.8	14.7
Unamortized loss on reacquired debt	18.9	20.1
Income taxes recoverable from customers, net	17.4	31.1
Red Rock deferred expenses	14.7	---
McClain Plant deferred expenses	12.4	18.7
Cogeneration credit rider under recovery	3.9	3.1
Miscellaneous	0.8	0.4
Total Regulatory Assets	$ 330.7	$ 319.2

Regulatory Liabilities
Accrued removal obligations, net	$ 139.7	$ 125.5
Fuel clause over recoveries	4.2	96.3
Deferred gain on sale of assets	1.4	2.7
Miscellaneous	2.9	---
Total Regulatory Liabilities	$ 148.2	$ 224.5

The Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which required the Company to separately disclose the items that had not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. OG&E met both criteria and, therefore, recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

The components of the SFAS No. 158 regulatory asset at December 31, 2007 and 2006 are as follows:

December 31 (In millions)	2007	2006
Defined benefit pension plan and retirement restoration plan:
Net loss	$ 112.3	$ 129.9
Prior service cost	4.8	21.9
Defined benefit postretirement plans:
Net loss	42.5	60.3
Net transition obligation	12.7	15.2
Prior service cost	2.3	3.8
Total	$ 174.6	$ 231.1

The following amounts in the SFAS No. 158 regulatory asset at December 31, 2007 are expected to be recognized as components of net periodic benefit cost in 2008:

(In millions)
Defined benefit pension plan and retirement restoration plan:
Net loss	$ 6.8
Prior service cost	1.2
Defined benefit postretirement plans:
Net loss	3.3
Net transition obligation	2.6
Prior service cost	1.5
Total	$ 15.4

In accordance with the OCC order received by OG&E in December 2005 in its Oklahoma rate case, OG&E was allowed to recover Oklahoma storm-related expenses exceeding a $3.5 million threshold. During 2007, OG&E’s service territory experienced several storms, including a significant ice storm in December 2007. At December 31, 2007, deferred storm-related expenses were approximately $35.9 million. This amount has been recorded as a regulatory asset as OG&E believes these expenses are probable of future recovery.

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.

In accordance with the OCC order received by OG&E in December 2005 in its Oklahoma rate case, OG&E was allowed to recover a certain amount of pension plan expenses. At December 31, 2007, there was approximately $24.8 million of expenses exceeding this level primarily related to pension settlement charges recorded by the Company during 2006 and 2007 (see Note 14 for a further discussion). These excess amounts have been recorded as a regulatory asset as OG&E believes these expenses are probable of future recovery.

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 amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is not included in OG&E’s rate base and does not otherwise earn a rate of return.

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.” The OCC authorized approximately $30.1 million of the $32.8 million regulatory asset balance at December 31, 2005 to be included in OG&E’s rate base for purposes of earning a return.

On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 megawatt (“MW”) Red Rock power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the Oklahoma Municipal Power Authority (“OMPA”). As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Consolidated Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. OG&E expects to receive an order from the OCC in this matter by the end of 2008.

As a result of the acquisition of a 77 percent interest in the 520 MW natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the 2002 agreed-upon settlement of an OG&E rate case (the “2002 Settlement Agreement”) with the OCC, OG&E had 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. At December 31, 2007, the McClain Plant regulatory asset was approximately $12.4 million which is being recovered over the remaining two-year time period as authorized in the OCC rate order which began in January 2006. Approximately $15.5 million of the McClain Plant deferred expenses are included in OG&E’s rate base for purposes of earning a return.

OG&E’s cogeneration credit rider was initially implemented in 2003 as part of the Oklahoma retail customer electric rates in order to return purchase power capacity payment reductions and any change in operating and maintenance expense related to cogeneration previously included in base rates to OG&E’s customers. The cogeneration credit rider was updated and approved by the OCC in December of each year through December 2006 and any over/under recovery of the cogeneration credit rider in the current year and prior periods was automatically included in the next year’s rider. The balance of the

cogeneration credit rider under recovery was approximately $3.9 million and $3.1 million, respectively, at December 31, 2007 and 2006. OG&E filed an application with the OCC in September 2007 to request a new cogeneration credit rider for years after 2007 as OG&E’s current cogeneration credit rider expired on December 31, 2007. In December 2007, the OCC issued an order approving a cogeneration credit rider that expires on December 31, 2009. The cogeneration credit rider under recovery was not included in OG&E’s rate base and did not otherwise earn a rate of return. The cogeneration credit rider under recovery is included in Other Current Assets on the Company’s Consolidated Balance Sheets.

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.

In December 2005, the OCC order in OG&E’s Oklahoma rate case required that any gains related to the sale of assets should be returned to customers through adjustments to electric rates. During 2006, OG&E sold certain assets for a gain of approximately $0.3 million which was recorded as a regulatory liability. There were no gains from the sale of assets in 2007. OG&E expects to continue this treatment for any future gains from the sale of assets.

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 effect on the Company’s Consolidated Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts.

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 $68.8 million and $45.0 million at December 31, 2007 and 2006, 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 final billing 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 collection of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable was approximately $3.8 million and $4.4 million at December 31, 2007 and 2006, respectively.

For OG&E, new business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Fuel Inventories

OG&E

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. For 2007 and 2006, these inventories were 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 $7.4 million and $13.7 million for 2007 and 2006, respectively, based on the average cost of fuel purchased. The amount of fuel inventory was approximately $44.3 million and $29.7 million at December 31, 2007 and 2006, respectively.

Effective January 1, 2008, OG&E’s inventory that is physically added to or withdrawn from storage or stockpiles will be valued using the weighted-average cost method in accordance with legislation that was passed in Oklahoma in 2007 which required that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. See Note 17 for a further discussion.

Enogex/OERI

Natural gas inventory is held by Enogex, through its transportation and storage business, and by OERI. The transportation and storage business maintains natural gas inventory to provide operational support for its pipeline deliveries. In addition, as part of its recurring buy and sell activity, OERI injects and withdraws natural gas into and out of inventory under the terms of its storage capacity contracts. In an effort to mitigate market price exposures, both businesses enter into contracts or hedging instruments to protect the cash flows associated with their inventory. All natural gas inventory held by Enogex is recorded at the lower of cost or market. During 2007 and 2006, Enogex recorded write-downs to market value related to natural gas storage inventory of approximately $3.6 million and $18.7 million, respectively. The amount of Enogex’s natural gas inventory was approximately $37.7 million and $35.9 million at December 31, 2007 and 2006, respectively. Natural gas storage inventory is presented in Fuel Inventories on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by Enogex’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. Enogex values all imbalances at an average of current market indices applicable to Enogex’s operations, not to exceed net realizable value.

Property, Plant and Equipment

OG&E

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction (“AFUDC”). Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property less net salvage is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, 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 replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

OG&E owns a 77 percent interest in the McClain Plant and, as disclosed below, only this 77 percent interest is reflected in the balances in the table below. The owner of the remaining 23 percent interest in the McClain Plant is the OMPA. OG&E and the OMPA are responsible for providing their own financing of capital expenditures. Also, only OG&E’s proportionate interest of any direct expenses of the McClain Plant such as fuel, maintenance expense and other operating expenses is included in the applicable financial statements captions in the Consolidated Statements of Income. The balance of OG&E’s interest in the McClain Plant asset was approximately $181.0 million and $180.2 million, respectively, at December 31, 2007 and 2006. The accumulated depreciation associated with OG&E’s interest in the McClain Plant was approximately $35.4 million and $25.3 million, respectively, at December 31, 2007 and 2006.

Enogex/OERI

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated Depreciation. For assets that do not belong to a common plant account, 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 and related accumulated depreciation are divided into the following major classes at December 31, 2007 and 2006, respectively.

	Total Property,		Net Property,
	Plant and	Accumulated	Plant and
December 31, 2007 (In millions)	Equipment	Depreciation	Equipment
OGE Energy (holding company)
Property, plant and equipment	$ 93.0	$ 65.4	$ 27.6
OGE Energy Corp. property, plant and equipment	93.0	65.4	27.6
OG&E
Distribution assets	2,361.4	792.0	1,569.4
Electric generation assets	2,114.0	1,062.8	1,051.2
Transmission assets	747.3	285.7	461.6
Intangible plant	35.8	29.7	6.1
Other property and equipment	217.0	71.7	145.3
OG&E property, plant and equipment	5,475.5	2,241.9	3,233.6
Enogex
Transportation and storage assets	729.2	191.4	537.8
Gathering and processing assets	684.0	237.2	446.8
Marketing assets	7.3	6.8	0.5
Enogex property, plant and equipment	1,420.5	435.4	985.1
Total property, plant and equipment	$ 6,989.0	$ 2,742.7	$ 4,246.3

	Total Property,		Net Property,
	Plant and	Accumulated	Plant and
December 31, 2006 (In millions)	Equipment	Depreciation	Equipment
OGE Energy. (holding company)
Property, plant and equipment	$ 80.7	$ 58.0	$ 22.7
OGE Energy Corp. property, plant and equipment	80.7	58.0	22.7
OG&E
Distribution assets	2,205.3	775.4	1,429.9
Electric generation assets	2,057.4	1,042.5	1,014.9
Transmission assets	663.2	265.1	398.1
Intangible plant	32.0	26.2	5.8
Other property and equipment	196.5	66.1	130.4
OG&E property, plant and equipment	5,154.4	2,175.3	2,979.1
Enogex
Transportation and storage assets	691.5	177.5	514.0
Gathering and processing assets	564.6	213.4	351.2
Marketing assets	7.6	7.1	0.5
Enogex property, plant and equipment	1,263.7	398.0	865.7
Total property, plant and equipment	$ 6,498.8	$ 2,631.3	$ 3,867.5

Depreciation

OG&E

The provision for depreciation, which was approximately 2.7 percent of the average depreciable utility plant for both 2007 and 2006, 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. In 2008, the provision for depreciation is projected to continue to be approximately 2.7 percent of the average depreciable utility plant. Amortization of intangibles is computed using the straight-line method. Approximately 83 percent of the remaining amortizable intangible plant balance at December 31, 2007 will be amortized over three years with approximately 17 percent of the remaining amortizable intangible plant balance at December 31, 2007 being amortized over their respective lives ranging from four to 25 years.

Enogex/OERI

Depreciation is computed principally on the straight-line method using estimated useful lives of three to 83 years for transportation and storage assets and three to 30 years for gathering and processing assets. For OERI, depreciation is computed principally on the straight-line method using estimated useful lives of three to 10 years. 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.

Asset Retirement Obligations

In accordance with SFAS No. 143, for periods subsequent to the initial measurement of an asset retirement obligations (“ARO”), the Company recognizes period-to-period changes in the liability for an ARO resulting from: (i) the passage of time; and (ii) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Also, in accordance with FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO 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 ARO is recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information existed. However, in some cases, there is insufficient information to estimate the fair value of an ARO. In these cases, the liability is initially recognized in the period in which sufficient information is available for the Company to make a reasonable estimate of the liability’s fair value.

Impairment of Assets

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 flows. 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 Company had no material impairments during 2007, 2006 or 2005.

Allowance for Funds Used During Construction

For OG&E, 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 5.78 percent, 7.79 percent and 3.78 percent for the years 2007, 2006 and 2005, respectively. The decrease in the AFUDC rates in 2007 was primarily due to a decrease in equity funds in the AFUDC calculation that resulted from a lower level of construction costs funded by short-term borrowings in 2007.

Collection of Sales Tax

In the course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability when it collects sales taxes from its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.

Revenue Recognition

OG&E

General

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.

SPP Purchases and Sales

In February 2007, OG&E began participating in the Southwest Power Pool’s (“SPP”) energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including OG&E, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ megawatt-hour (“MWH”) entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Consolidated Financial Statements.

Enogex/OERI

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

contracted prices. Estimated operating revenues are reflected in Accounts Receivable on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.

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, “Accounting for Derivative Instruments and Hedging Activities.” 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, Price Risk Management Liabilities or against the brokerage deposits in Other Current Assets in the Consolidated Balance Sheets.

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.

Stock-Based Compensation

The Company adopted SFAS No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method, effective January 1, 2006, which required the Company to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. See Note 4 for a further discussion related to the Company’s stock-based compensation. The following table reflects pro forma net income and income per average common share for 2005 had the Company elected to adopt the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” for options granted under the Company’s stock-based employee compensation plans. For purposes of this pro forma disclosure, the value of the options was determined using a Black-Scholes option pricing formula and amortized to expense over the options’ vesting periods. Pro forma information is not included for 2006 as all share-based payments have been accounted for under SFAS No. 123(R).

Year ended December 31 (In millions, except per share data)	2005

Net income, as reported	$ 211.0

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	0.5

Pro forma net income	$ 210.5

Income per average common share
Basic – as reported	$ 2.34
Diluted – as reported	$ 2.32
Basic – pro forma	$ 2.33
Diluted – pro forma	$ 2.32

Accrued Vacation

The Company accrues vacation pay by establishing a liability for vacation earned during the current year, but not payable until the following year.

Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive loss at December 31, 2007 and 2006 are as follows:

December 31 (In millions)	2007	2006
Defined benefit pension plan:
Net loss, net of tax	$ (18.0)	$ (20.7)
Prior service cost, net of tax	(0.8)	(4.1)
Defined benefit postretirement plans:
Net loss, net of tax	(3.7)	(5.4)
Net transition obligation, net of tax	(0.7)	(0.8)
Prior service cost, net of tax	(0.4)	(0.7)
Deferred hedging gains (losses), net of tax	(55.7)	5.6
Settlement and amortization of cash flow hedge, net of tax	(1.7)	(1.9)
Total accumulated other comprehensive loss, net of tax	$ (81.0)	$ (28.0)

Approximately $25.8 million of the deferred hedging losses at December 31, 2007 are expected to be recognized into earnings during 2008.

Defined Benefit Pension and Postretirement Plans

The Company is required to disclose the amounts in accumulated other comprehensive loss at December 31, 2007 that are expected to be recognized as components of net periodic benefit cost in 2008 which are as follows:

(In millions)
Defined benefit pension plan:
Net loss, net of tax	$ 1.0
Prior service cost, net of tax	0.2
Defined benefit postretirement plans:
Net loss, net of tax	0.3
Prior service cost, net of tax	0.3
Net transition obligation, net of tax	0.1
Total	$ 1.9

Environmental Costs

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E or Enogex have been designated as one of several potentially responsible parties, the amount accrued represents OG&E’s or Enogex’s estimated share of the cost.

Reclassifications

Certain prior year amounts have been reclassified on the Consolidated Financial Statements to conform to the 2007 presentation primarily related to the net presentation of Price Risk Management Assets and Liabilities as discussed in Note 6.

2.	Formation of OGE Enogex Partners L.P.

the closing of the Offering, Enogex Inc., which is currently an Oklahoma corporation, would convert to Enogex LLC, a Delaware limited liability company. In connection with the Offering, the Company is expected to contribute an approximately 25 percent membership interest in Enogex LLC to a wholly owned subsidiary of the Partnership that would serve as Enogex LLC’s managing member and would control its assets and operations. A wholly owned subsidiary of the Company will retain the remaining approximately 75 percent membership interest in Enogex LLC. It is currently contemplated that at the completion of the Offering, the Company will indirectly own an approximate 68 percent limited partner interest and a two percent general partner interest in the Partnership.

3.	Accounting Pronouncement

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the guidance in footnote 3 of Emerging Issues Task Force 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.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 generally are to be applied prospectively as of the beginning of the fiscal year in which it is initially applied. The Company adopted this new standard effective January 1, 2008. The adoption of this new standard is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

4.	Stock-Based Compensation

On January 21, 1998, the Company adopted a Stock Incentive Plan (the “1998 Plan”). In 2003, the Company adopted, and its shareowners approved, a new Stock Incentive Plan (the “2003 Plan” and together with the 1998 Plan, the “Plans”). The 2003 Plan replaced the 1998 Plan and no further awards will be granted under the 1998 Plan. As under the 1998 Plan, under the 2003 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 2,700,000 shares under the 2003 Plan.

Prior to January 1, 2006, the Company accounted for the Plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” as permitted by SFAS No. 123. The Company also previously adopted the disclosure provisions under SFAS No. 123 and SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The Company recorded compensation expense of approximately $0.9 million pre-tax ($0.5 million after tax) in 2005 related to its performance units in Other Operation and Maintenance Expense in the Consolidated Statement of Income. No compensation expense related to stock options was recognized in 2005 as all options granted under the Plans had an exercise price equal to the market value of the Company’s common stock on the grant date. Effective January 1, 2006, the Company adopted SFAS No. 123(R) using the modified prospective transition method. Under that transition method, the Company’s compensation cost recognized in the first quarter of 2006 included: (i) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R); and (ii) compensation cost for all share-based payments granted in the first quarter of 2006 based on the fair value calculated in accordance with the provisions of SFAS No. 123(R). Results for prior periods were not restated.

As a result of adopting SFAS No. 123(R) on January 1, 2006, the Company recorded compensation expense of approximately $8.6 million pre-tax ($5.3 million after tax, or $0.06 per basic and diluted share) in 2006 related to the Company’s share-based payments. Also, as a result of adopting SFAS No. 123(R), the Company recorded a cumulative effect adjustment of approximately $0.4 million pre-tax ($0.2 million after tax, or less than $0.01 per basic and diluted share) on January 1, 2006 for outstanding non-vested share-based compensation grants at December 31, 2005. The Company determined that the cumulative effect adjustment was immaterial for presentation purposes and is, therefore, included in Other Operation and Maintenance Expense in the Consolidated Statement of Income. The Company recorded compensation expense of approximately $3.8 million pre-tax ($2.3 million after tax, or $0.03 per basic and diluted share) in 2007 related to the Company’s share-based payments.

The Company issues new shares to satisfy stock option exercises. During 2007, 2006 and 2005, there were 496,565 shares, 738,426 shares and 606,802 shares, respectively, of new common stock issued pursuant to the Company’s Plans related to exercised stock options and payouts of earned performance units. The Company received approximately $8.2 million and $14.5 million in 2007 and 2006, respectively, related to exercised stock options.

Prior to the adoption of SFAS No. 123(R), the Company presented all tax benefits of deductions resulting from the exercise of stock options or other share-based payments as operating cash flows in the Consolidated Statements of Cash Flows. SFAS No. 123(R) requires cash flows resulting in tax benefits from tax deductions in excess of the compensation cost recognized for share-based payments (“excess tax benefits”) to be classified as financing cash flows. The Company recorded an excess tax benefit of approximately $3.5 million in 2007 related to the Company’s 2007 share-based payments. The Company realized an excess tax benefit of approximately $2.8 million in 2007 related to the Company’s 2006 share-based payments, which amount was presented as a financing cash inflow and realized when the Company’s 2006 income tax return was filed in September 2007. The Company recorded an excess tax benefit of approximately $2.8 million in 2006 related to the Company’s 2006 share-based payments. The Company realized an excess tax benefit of approximately $1.4 million in 2006 related to the Company’s 2005 share-based payments, which amount was presented as a financing cash inflow and realized when the Company’s 2005 income tax return was filed in August 2006. The Company realized an excess tax benefit of approximately $0.8 million during 2005 related to the Company’s 2004 share-based payments.

Performance Units

Under the Plans, the Company has issued performance units which represent the value of one share of the Company’s common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Plans). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant’s number of full months of service during the three-year award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The following table is a summary of the terms of the Company’s outstanding performance units awarded during 2005, 2006 and 2007.

			SFAS No. 123(R)
Condition	Settlement	Vesting Period	Classification

Total Shareholder Return	2/3 – Stock (A)	3-year cliff	Equity
	1/3 – Cash	3-year cliff	Liability

Earnings Per Share	2/3 – Stock (A)	3-year cliff	Equity
	1/3 – Cash	3-year cliff	Liability

(A) All of the Company’s 2006 and 2007 performance units will be settled in stock.

The performance units granted based on total shareholder return (“TSR”) are contingently awarded and will be payable in cash or shares of the Company’s common stock (other than performance units awarded in 2006 and 2007, which will be payable only in shares of common stock) subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a three-year award cycle is dependent on the Company’s TSR ranking relative to a peer group of companies. The performance units granted based on earnings per share (“EPS”) are contingently awarded and will be payable in cash or shares of the Company’s common stock (other than performance units awarded in 2006 and 2007, which will be payable only in shares of common stock) based on the Company’s EPS growth over a three-year award cycle compared to a target set at the time of the grant by the Compensation Committee of the Company’s Board of Directors. If there is no or only a partial payout for the performance units at the end of the three-year award cycle, the unearned performance units are cancelled. During 2007, 2006 and 2005, the Company awarded 162,730, 239,856 and 201,794 performance units, respectively, to certain employees of the Company and its subsidiaries.

Performance Units – Total Shareholder Return

The Company recorded compensation expense of approximately $2.3 million pre-tax ($1.4 million after tax), $6.5 million pre-tax ($4.0 million after tax) and $0.6 million pre-tax ($0.4 million after tax) in 2007, 2006 and 2005, respectively, related to the performance units based on TSR. The fair value of the performance units based on TSR was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units settled in stock is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Compensation expense for the performance units settled in cash is based on the change in the fair value of the performance units for each reporting period. This liability for the performance units will be remeasured at each reporting date until the date of settlement. Dividends are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. Expected price volatility is based on the historical volatility of the Company’s common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to the Company’s performance units based on TSR. The fair value of the performance units based on TSR was calculated based on the following assumptions at the grant date.

	2007	2006	2005
Expected dividend yield	3.6%	4.9%	5.3%
Expected price volatility	15.9%	16.8%	22.3%
Risk-free interest rate	4.47%	4.66%	3.28%
Expected life of units (in years)	2.95	2.85	2.85
Fair value of units granted	$ 24.18	$ 22.93	$ 21.56

A summary of the activity for the Company’s performance units based on TSR at December 31, 2007 and changes during 2007 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on TSR is determined by the Company’s TSR for such period compared to a peer group and payout requires the approval of the Compensation Committee of the Company’s Board of Directors. Payouts, if any, are made in two-thirds stock and one-third cash (other than payouts of performance units awarded in 2006 and 2007, which will be made only in common stock) and are considered made when the payout is approved by the Compensation Committee.

		Stock	Aggregate
	Number	Conversion	Intrinsic
(dollars in millions)	of Units	Ratio (A)	Value
Units Outstanding at 12/31/06	440,263	1 : 1
Granted (B)	122,044	1 : 1
Converted	(132,845)	1 : 1	$ 4.8
Forfeited	(66,314)	1 : 1
Units Outstanding at 12/31/07	363,148	1 : 1	$ 14.1
Units Fully Vested at 12/31/07 (C)	124,886	1 : 1	$ 5.9

(A) One performance unit = one share of the Company’s common stock.

(B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(C) These performance units, which were awarded in 2005 and became fully vested at December 31, 2007, were certified by the Compensation Committee of the Company’s Board of Directors in February 2008.

A summary of the activity for the Company’s non-vested performance units based on TSR at December 31, 2007 and changes during 2007 are summarized in the following table:

		Weighted-Average
	Number	Grant Date
	of Units	Fair Value
Units Non-Vested at 12/31/06	307,418	$ 22.33
Granted (D)	122,044	$ 24.18
Vested (E)	(124,886)	$ 21.56
Forfeited	(66,314)	$ 23.25
Units Non-Vested at 12/31/07 (F)	238,262	$ 23.42

(D) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(E) These performance units, which were awarded in 2005 and became fully vested at December 31, 2007, were certified by the Compensation Committee of the Company’s Board of Directors in February 2008.

(F) Of the 238,262 performance units not vested at December 31, 2007, 216,023 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2007, there was approximately $2.3 million in unrecognized compensation cost related to non-vested performance units based on TSR which is expected to be recognized over a weighted-average period of 1.56 years.

Performance Units – Earnings Per Share

The Company recorded compensation expense of approximately $1.5 million pre-tax ($0.9 million after tax), $2.0 million pre-tax ($1.2 million after tax) and $0.5 million pre-tax ($0.3 million after tax), in 2007, 2006 and 2005, respectively, related to the performance units based on EPS. The fair value of the performance units based on EPS is based on grant date fair value which is equivalent to the price of one share of the Company’s common stock on the date of grant. The fair value of performance units based on EPS varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company’s performance units based on EPS. The grant date fair value of the 2005, 2006 and 2007 performance units was $23.78, $28.00 and $33.59, respectively.

A summary of the activity for the Company’s performance units based on EPS at December 31, 2007 and changes during 2007 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on EPS growth is determined by the Company’s growth in EPS for such period compared to a target set at the beginning of the three-year period by the Compensation Committee of the Company’s Board of Directors and payout requires the approval of the Compensation Committee. Payouts, if any, are made in two-thirds stock and one-third cash (other than payouts of performance units awarded in 2006 and 2007, which will be made only in common stock) and are considered made when approved by the Compensation Committee.

		Stock	Aggregate
	Number	Conversion	Intrinsic
(dollars in millions)	of Units	Ratio (A)	Value
Units Outstanding at 12/31/06	102,459	1:1
Granted (B)	40,686	1:1
Forfeited	(22,163)	1:1
Units Outstanding at 12/31/07	120,982	1:1	$ 7.6
Units Fully Vested at 12/31/07 (C)	41,618	1:1	$ 3.0

(A) One performance unit = one share of the Company’s common stock

(B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

A summary of the activity for the Company’s non-vested performance units based on EPS at December 31, 2007 and changes during 2007 are summarized in the following table:

		Weighted-Average
	Number	Grant Date
	of Units	Fair Value
Units Non-Vested at 12/31/06	102,459	$ 26.15
Granted (D)	40,686	$ 33.59
Vested (E)	(41,618)	$ 23.78
Forfeited	(22,163)	$ 29.72
Units Non-Vested at 12/31/07 (F)	79,364	$ 30.21

(D) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(F) Of the 79,364 performance units not vested at December 31, 2007, 72,008 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2007, there was approximately $0.8 million in unrecognized compensation cost related to non-vested performance units based on EPS which is expected to be recognized over a weighted-average period of 1.00 years.

Stock Options

The Company recorded no compensation expense in 2007 related to stock options because at December 31, 2006, there was no unrecognized compensation cost related to non-vested options, which became fully vested in January 2007. The Company recorded compensation expense of approximately $0.1 million pre-tax (less than $0.1 million after tax) in 2006 related to stock options. No compensation expense related to stock options was recognized in 2005 as all options granted under the Plans had an exercise price equal to the market value of the Company’s common stock on the grant date.

A summary of the activity for the Company’s options at December 31, 2007 and changes during 2007 are summarized in the following table:

			Aggregate	Weighted-Average
	Number	Weighted-Average	Intrinsic	Remaining
(dollars in millions)	of Options	Exercise Price	Value	Contractual Term
Options Outstanding at 12/31/06	1,485,602	$ 21.90
Exercised	(346,674)	$ 23.74	$ 4.9
Expired	(11)	$ 16.69
Options Outstanding at 12/31/07	1,138,917	$ 21.34	$ 17.0	4.28 years
Options Fully Vested and Exercisable at 12/31/07	1,138,917	$ 21.34	$ 17.0	4.28 years

A summary of the activity for the Company’s non-vested options at December 31, 2007 and changes during 2007 are summarized in the following table:

		Weighted-Average
	Number	Grant Date
	of Options	Fair Value
Options Non-Vested at 12/31/06	91,382	$ 2.05
Vested	(91,382)	$ 2.05
Options Non-Vested at 12/31/07	---	$ ---

5.	Loss on Retirement and Asset Retirement Obligation of Fixed Assets

OG&E had a power supply contract with a large industrial customer that expired on June 1, 2006. OG&E evaluated options to utilize the assets dedicated to that customer and decided to retire these assets as of June 30, 2006. The carrying amount of these assets at June 30, 2006 was approximately $6.8 million, which was recorded as a pre-tax loss during the second quarter of 2006. This loss was included in Other Expense in the Consolidated Statement of Income. Also, as part of the settlement of the ARO for these assets, OG&E recorded a reduction to the previously recorded ARO for these assets of approximately $0.9 million in 2006 due to an agreement with a third party to provide removal and remediation services. This reduction is included in Other Expense in the Consolidated Statement of Income.

6.	Price Risk Management Assets and Liabilities

Non-Trading Activities

The Company periodically utilizes derivative contracts to manage the exposure of its assets to unfavorable changes in commodity prices, as well as to reduce exposure to adverse interest rate fluctuations. During 2007 and 2006, the Company’s use of non-trading price risk management instruments involved the use of commodity price futures, commodity price swap contracts, commodity price option features and treasury lock agreements. The commodity price futures and commodity price swap contracts involved the exchange of fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. The commodity price option contracts involved the payment of a premium for the right, but not the obligation, to exchange fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. The treasury lock agreements help protect against the variability of future interest payments of long-term debt that was issued by OG&E.

In accordance with SFAS No. 133, the Company recognizes its non-exchange traded derivative instruments as Price Risk Management assets or liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Consolidated Balance Sheets. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method prescribed by SFAS No. 133. Under the change in fair value method, the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected.

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133. Normal purchases and normal sales contracts are not recorded in Price Risk Management assets or liabilities in the Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales to: (i) commodity contracts for the purchase and sale of natural gas; (ii) commodity contracts for the sale of natural gas liquids produced by its subsidiary, Enogex Products Corporation (“Products”); (iii) electric power contracts by OG&E; and (iv) fuel procurement by OG&E.

At December 31, 2007, OG&E’s treasury lock agreements were not designated as cash flow hedges under SFAS No. 133. The 2007 treasury lock agreements were settled on January 29, 2008. At December 31, 2006, OG&E’s treasury lock agreements were designated as cash flow hedges under SFAS No. 133. The 2006 treasury lock agreements expired March 29, 2007.

Trading Activities

The Company, through OERI, engages in energy trading activities primarily related to the purchase and sale of natural gas. Contracts utilized in these activities generally include forward swap contracts as well as over-the-counter and exchange traded futures and options. Energy trading activities are accounted for in accordance with SFAS No. 133 and EITF Issue No. 02-3. In accordance with SFAS No. 133, financial instruments that qualify as derivatives are reflected at fair value with the resulting unrealized gains and losses recorded as Price Risk Management Assets or Price Risk Management Liabilities in the Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement, or against the brokerage deposits in Other Current Assets. The offsetting unrealized gains and losses from changes in the market value of open contracts are included in Natural Gas Pipeline Operating Revenues in the Consolidated Statements of Income or in Other

Comprehensive Income for derivatives designated and qualifying as cash flow hedges in accordance with SFAS No. 133. Energy trading contracts resulting in delivery of a commodity that meet the requirements of EITF Issue No. 99-19, “Reporting Revenues Gross as a Principal or Net as an Agent,” are included as sales or purchases in the Consolidated Statements of Income depending on whether the contract relates to the sale or purchase of the commodity.

In the second quarter of 2007, the Company adopted FASB Interpretation No. 39 (As Amended), “Offsetting of Amounts Related to Certain Contracts – an interpretation of APB Opinion No. 10 and FASB Statement No. 105,” which states that fair value amounts recognized for forward, interest rate swap, currency swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, currency swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheet. The Company has presented the fair values of its contracts under master netting agreements using a net fair value presentation. If these transactions with the same counterparty were presented on a gross basis in the Consolidated Balance Sheets, current Price Risk Management assets and liabilities would be approximately $10.0 million and $51.4 million, respectively, at December 31, 2007, and non-current Price Risk Management assets and liabilities would be approximately $2.6 million and $38.9 million, respectively, at December 31, 2007. If these transactions with the same counterparty were presented on a gross basis in the Consolidated Balance Sheets, current Price Risk Management assets and liabilities would be approximately $41.9 million and $9.2 million, respectively, at December 31, 2006, and non-current Price Risk Management assets and liabilities would be approximately $1.7 million and $1.1 million, respectively, at December 31, 2006.

7.	Enogex – Discontinued Operations

In May 2006, Enogex’s wholly owned subsidiary, Enogex Gas Gathering, L.L.C. (“Gathering”), sold certain gas gathering assets in the Kinta, Oklahoma area (the “Kinta Assets”), which included approximately 568 miles of gathering pipeline and 22 compressor units, for approximately $92.9 million. Enogex recorded an after tax gain of approximately $34.1 million from this sale in the second quarter of 2006.

In October 2005, Enogex sold its interest in Enogex Arkansas Pipeline Corporation (“EAPC”), which held a 75 percent interest in the NOARK Pipeline System Limited Partnership, for approximately $177.4 million. Enogex recorded an after tax gain of approximately $36.7 million from this sale in the fourth quarter of 2005.

In August 2005, Enogex Compression Company, LLC (“Enogex Compression”) sold its interest in Enerven Compression Services, LLC (“Enerven”), a joint venture focused on the rental of natural gas compression assets, for approximately $7.3 million. Enogex Compression recognized an after tax gain of approximately $1.8 million from this sale in the third quarter of 2005.

The Consolidated Financial Statements of the Company have been reclassified to reflect the above sales as discontinued operations. Accordingly, revenues, costs and expenses and cash flows from these sales have been excluded from the respective captions in the Consolidated Financial Statements and have been separately reported as discontinued operations in the applicable financial statement captions. As the above sales occurred prior to 2007, there are no results of operations for discontinued operations during 2007. Summarized financial information for the discontinued operations as of December 31 is as follows:

CONSOLIDATED STATEMENTS OF INCOME DATA

Year ended December 31 (In millions)	2007	2006	2005
Operating revenues from discontinued operations	$ ---	$ 9.4	$ 106.0
Income from discontinued operations before taxes	---	59.1	84.2

8.	Supplemental Cash Flow Information

The following table discloses information about investing and financing activities that affect recognized assets and liabilities but which do not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.

Year ended December 31 (In millions)	2007	2006	2005
NON-CASH INVESTING AND FINANCING ACTIVITIES

Change in fair value of long-term debt due to interest rate swaps	$ ---	$ ---		$ (7.8)
Power plant long-term service agreement	0.7	---		---

SUPPLEMENTAL CASH FLOW INFORMATION

Cash Paid During the Period for
Interest (net of interest capitalized of $4.9, $5.4, $2.2)	$ 93.5	$ 85.5		$ 95.9
Income taxes (net of income tax refunds)	86.6	122.7		42.0

9.	Income Taxes

The items comprising income tax expense are as follows:

Year ended December 31 (In millions)	2007	2006		2005
Provision (Benefit) for Current Income Taxes from Continuing
Operations
Federal	$ 96.0	$ 96.0		$ 43.0
State	3.9	(7.4)		5.0
Total Provision for Current Income Taxes from
Continuing Operations	99.9	88.6		48.0
Provision for Deferred Income Taxes, net from
Continuing Operations
Federal	18.2	35.4		26.4
State	2.7		1.9		---
Total Provision for Deferred Income Taxes, net from
Continuing Operations	20.9		37.3		26.4
Deferred Federal Investment Tax Credits, net	(4.8)		(5.0)		(5.1)
Income Taxes Relating to Other Income and Deductions	0.7		(0.4)		(0.7)
Total Income Tax Expense from Continuing Operations	$ 116.7		$ 120.5		$ 68.6

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2002. Income taxes are generally allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its federal investment tax credits on a ratable basis throughout the year. This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income. The following schedule reconciles the statutory federal tax rate to the effective income tax rate:

Year ended December 31	2007	2006	2005
Statutory federal tax rate	35.0%	35.0%	35.0%
State income taxes, net of federal income tax benefit	1.9	2.8	1.5
Amortization of net unfunded deferred taxes	0.8	0.7	1.0
Medicare Part D subsidy	(0.3)	(0.7)	(1.2)
401(k) dividends	(1.2)	(0.9)	(1.8)
Federal investment tax credits, net	(1.3)	(1.4)	(2.2)
Federal renewable energy credit (A)	(2.0)	---	---
Excess deferred taxes (B)	---	---	(2.3)
Other	(0.6)	(0.7)	(0.1)
Effective income tax rate as reported	32.3%	34.8%	29.9%

(A) These are credits OG&E began earning associated with the production from its 120 MW wind farm in northwestern Oklahoma (“Centennial”) that was placed in service during January 2007.

(B) During 2005, the Company performed a detailed analysis of all deferred tax assets and liabilities. In connection with this analysis, it was determined that an excess liability existed. The removal of this excess liability caused a permanent difference in the effective tax rate for 2005 of approximately 2.3 percent.

In connection with the filing of the Company’s 2002 consolidated income tax returns, OG&E elected to change its tax method of accounting related to the capitalization of costs for self-constructed assets to another method prescribed in the Income Tax regulations. The accounting method change was for income tax purposes only. For financial accounting purposes, the only change was recognition of the impact of the cash flow generated by accelerating income tax deductions. This was reflected in the financial statements as a switch from current income taxes payable to deferred income taxes payable. This tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under the prior method, resulting in a consolidated tax net operating loss for 2002. This tax net operating loss eliminated the Company’s current federal and state income tax liability for 2002 and 2003 and all estimated payments made for 2002 were refunded. The Company received federal and state income tax refunds of approximately $50.8 million during 2003 related to this tax accounting method change.

During 2005, new guidelines were issued by the Internal Revenue Service (“IRS”) related to the change in the method of accounting used to capitalize costs for self-construction discussed above. In the Company’s IRS examination for years 2002 and 2003, the IRS stated that it disagreed with the change made by OG&E.

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of costs for self-constructed assets discussed above. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. OG&E reached a final settlement with the IRS on November 27, 2007 related to the tax method of accounting for the capitalization of costs for self-constructed assets. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

(In millions)

Balance at January 1, 2007	$ 66.4
Settlements with tax authorities	(66.4)
Balance at December 31, 2007	$ ---

The Company recognizes accrued interest related to tax benefits in interest expense and recognizes penalties in other expense. OG&E recorded interest expense associated with the IRS audit of approximately $3.3 million in 2005, $0.3 million in 2006 and $2.6 million through October 2007. On November 27, 2007, OG&E reached a final settlement with the IRS related to the tax method of accounting, which resulted in the reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position. At December 31, 2007, the Company had approximately $2.9 million of accrued interest related to the capitalization of costs for self-constructed assets discussed above.

The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.

The deferred tax provisions, set forth above, are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Accumulated Deferred Taxes at December 31, 2007 and 2006, respectively, were as follows:

December 31 (In millions)		2007		2006
Current Accumulated Deferred Tax Assets
Derivative instruments	$	19.3	$	---
Accrued vacation		6.4		6.2
Accrued liabilities		6.3		3.4
Uncollectible accounts		1.6		1.7
Other		4.5		2.6
Total Current Accumulated Deferred Tax Assets		38.1		13.9
Current Accumulated Deferred Tax Liabilities
Derivative instruments		---		(3.3)
Current Accumulated Deferred Tax Assets, net	$	38.1	$	10.6
Non-Current Accumulated Deferred Tax Liabilities
Accelerated depreciation and other property related differences	$	780.3	$	793.7
Regulatory asset		96.0		75.9
Company pension plan		60.6		41.4
Income taxes refundable to customers, net		6.7		13.0
Bond redemption-unamortized costs		6.1		6.4
Total Non-Current Accumulated Deferred Tax Liabilities		949.7		930.4
Non-Current Accumulated Deferred Tax Assets
Regulatory liabilities		(34.3)		(29.1)
Postretirement medical and life insurance benefits		(34.3)		(30.8)
Derivative instruments		(18.9)		---
Deferred federal investment tax credits		(8.5)		(10.4)
Other		(0.1)		(0.9)
Total Non-Current Accumulated Deferred Tax Assets		(96.1)		(71.2)
Non-Current Accumulated Deferred Income Tax Liabilities, net	$	853.6	$	859.2

The Company fully utilized all of its Oklahoma investment tax credit carryovers from 2006 and prior periods in 2007. During 2007, additional Oklahoma tax credits of approximately $14.2 million were generated or purchased by the Company. The Company currently believes that approximately $9.7 million of these state tax credit amounts will be utilized in 2007 and approximately $4.5 million will be carried over to 2008 and later years. Credits not utilized in 2007 will begin expiring in 2018.

10.

Common Stock

In July 2005, the Company filed a Form S-3 Registration Statement to register 7,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”). Under the terms of the DRIP/DSPP, the Company may accept requests for optional investments in amounts greater than $0.1 million per year and may offer a discount of up to three percent from current market prices. This program allows the Company to sell additional common stock at a smaller discount than that normally incurred in a secondary equity offering. During the years ended December 31, 2007, 2006 and 2005, the Company purchased common stock on the open market to satisfy the common stock requirements of the DRIP/DSPP and therefore did not issue any new shares of common stock.

At December 31, 2007, there were 11,805,879 shares of unissued common stock reserved for issuance under various employee and Company stock plans.

Shareowners Rights Plan

In December 1990, OG&E adopted a Shareowners Rights Plan designed to protect shareowners’ interests in the event that OG&E was confronted with an unfair or inadequate acquisition proposal. In connection with a corporate restructuring, the Company adopted a substantially identical Shareowners Rights Plan in August 1995. Pursuant to the plan, the Company declared a dividend distribution of one “right” for each share of Company common stock. As a result of the June 1998 two-for-one stock split, each share of common stock is now entitled to one-half of a right. Each right entitles the holder to purchase from the Company one one-hundredth of a share of new preferred stock of the Company under certain circumstances. The rights may be exercised if a person or group announces its intention to acquire, or does acquire, 20 percent or more of the Company’s outstanding common stock. Under certain circumstances, the holders of the rights will be entitled to purchase either shares of common stock of the Company or common stock of the acquirer at a reduced percentage of the market value. In October 2000, the Shareowners Rights Plan was amended and restated to extend the expiration date to December 11, 2010 and to change the exercise price of the rights.

The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.

11.

Earnings Per Share

Outstanding shares for purposes of basic and diluted earnings per average common share were calculated as follows:

Year ended December 31 (In millions)	2007	2006	2005

Average Common Shares Outstanding
Basic average common shares outstanding	91.7	91.0	90.3
Effect of dilutive securities:
Employee stock options and unvested stock grants	0.3	0.3	0.2
Contingently issuable shares (performance units)	0.5	0.8	0.3
Diluted average common shares outstanding	92.5	92.1	90.8
Anti-dilutive shares excluded from EPS calculation	---	0.1	0.2

12.

Long-Term Debt

A summary of the Company’s long-term debt is included in the Consolidated Statements of Capitalization. At December 31, 2007, the Company was in compliance with all of its debt agreements.

Optional Redemption of Long-Term Debt

OG&E has three series of variable-rate industrial authority bonds (the “Bonds”) with optional redemption provisions that allow the holders to request repayment of the Bonds at various dates prior to the maturity. The Bonds, which can be tendered at the option of the holder during the next 12 months, are as follows (dollars in millions):

SERIES	DATE DUE	AMOUNT
3.25% - 4.07% Garfield Industrial Authority, January 1, 2025		$ 47.0
3.24% - 4.03% Muskogee Industrial Authority, January 1, 2025		32.4
3.35% - 4.11% Muskogee Industrial Authority, June 1, 2027		56.0
Total (redeemable during next 12 months)		$ 135.4

All of these Bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the Bond by delivering an irrevocable notice to the tender agent stating the principal amount of the Bond, payment instructions for the purchase price and the business day the Bond is to be purchased. The repayment option may only be exercised by the holder of a Bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of Bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company believes that it has sufficient long-term liquidity to meet these obligations.

Long-Term Debt Maturities

The Company has previously incurred costs related to debt refinancings. Unamortized debt expense and unamortized loss on reacquired debt are classified as Deferred Charges and Other Assets and the unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

Issuance of New Long-Term Debt

In January 2008, OG&E issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings. OG&E entered into two separate treasury lock arrangements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of the long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008.

13.

Short-Term Debt

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by loans under short-term bank facilities. The short-term debt balance was approximately $295.8 million at December 31, 2007 at a weighted-average interest rate of 5.54 percent. There was no short-term debt outstanding at December 31, 2006. The following table shows the Company’s revolving credit agreements and available cash at December 31, 2007.

Revolving Credit Agreements and Available Cash (In millions)
	Amount	Amount	Weighted-Average
Entity	Available	Outstanding	Interest Rate	Maturity
OGE Energy Corp. (A)	$ 600.0	$ 295.0	5.54%	December 6, 2012 (C)
OG&E (B)	400.0	---	---	December 6, 2012 (C)
	1,000.0	295.0	5.54%
Cash	8.8	N/A	N/A	N/A
Total	$ 1,008.8	$ 295.0	5.54%

(A) This bank facility is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2007, there was approximately $295.0 million in outstanding commercial paper borrowings.

(B) This bank facility is available to back up OG&E’s commercial paper borrowings and to provide revolving credit borrowings. At December 31, 2007, OG&E had outstanding approximately $3.1 million supporting letters of credit and no commercial paper borrowings.

(C) In December 2006, the Company and OG&E amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for the Company and $400 million for OG&E. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods. In November 2007, the Company and OG&E utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at the end of the two renewal options to convert the outstanding balance to a one-year term loan.

The Company’s and OG&E’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the market turmoil in August 2007. As a result of the market turmoil in August 2007, the Company and OG&E utilized borrowings under their revolving credit agreements. During the third and fourth quarters of 2007, the Company and OG&E repaid the borrowings under their revolving credit agreements and began utilizing commercial paper in the commercial paper market. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the Company 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. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit. Also, any downgrade below investment grade at OERI could require the Company to issue guarantees to support some of OERI’s marketing operations.

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 $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2007 and ending December 31, 2008.

14.

Retirement Plans and Postretirement Benefit Plans

In September 2006, the FASB issued SFAS No. 158 which required an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements was effective for the year ended December 31, 2006 for the Company.

Defined Benefit Pension Plan

All eligible employees of the Company and participating affiliates are covered by a non-contributory defined benefit pension plan. For employees hired on or after February 1, 2000, the pension plan is a cash balance plan, under which the Company annually will credit to the employee’s account an amount equal to five percent of the employee’s annual compensation plus accrued interest. Employees hired prior to February 1, 2000 will receive the greater of the cash balance benefit or a benefit based primarily on years of service and the average of the five highest consecutive years of compensation during an employee’s last 10 years prior to retirement, with reductions in benefits for each year prior to age 62 unless the employee’s age and years of credited service equal or exceed 80.

It is the Company’s policy to fund the plan on a current basis based on the net periodic SFAS No. 87, “Employers’ Accounting for Pensions,” pension expense as determined by the Company’s actuarial consultants. Additional amounts may be contributed from time to time to increase the funded status of the plan. During 2007 and 2006, the Company made contributions to its pension plan of approximately $50.0 million and $90.0 million, respectively, to help ensure that the pension plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2008, the Company may contribute up to $50.0 million to its pension plan. The expected contribution to the pension plan, anticipated to be in the form of cash, is a discretionary contribution and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

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

(In millions)	OG&E (A)	Enogex	OGE Energy	Total

Pension Settlement Charges:
2007	$ 13.3	$ 0.5	$ 2.9	$ 16.7

2006	$ 13.3	$ 0.8	$ 3.0	$ 17.1

Retirement Restoration Plan Settlement Charge:
2007	$ 0.1	$ ---	$ 2.2	$ 2.3

(A) OG&E’s Oklahoma jurisdictional portion of these charges were recorded as a regulatory asset (see Note 1 for a further discussion).

Pension Plan Costs and Assumptions

Plan Investments, Policies and Strategies

The pension plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, listed common stocks and corporate debt. The following table shows, by major category, the percentage of the fair value of the plan assets held at December 31, 2007 and 2006:

December 31	2007	2006
Equity securities	61 %	64 %
Debt securities	37 %	34 %
Other	2 %	2 %
Total	100 %	100 %

The pension plan assets are held in a trust which follows an investment policy and strategy designed to maximize the long-term investment returns of the trust at prudent risk levels. Common stocks are used as a hedge against moderate inflationary conditions, as well as for participation in normal economic times. Fixed income investments are utilized for high current income and as a hedge against deflation. The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company’s members and the Company’s Investment Committee (the “Investment Committee”).

The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for their respective portfolio. The table below shows the target asset allocation percentages for each major category of plan assets:

Asset Class	Target Allocation	Minimum	Maximum
Domestic Equity	30 %	--- %	60 %
Domestic Mid-Cap Equity	10 %	--- %	10 %
Domestic Small-Cap Equity	10 %	--- %	10 %
International Equity	10 %	--- %	10 %
Fixed Income Domestic	38 %	30 %	70 %
Cash	2 %	--- %	5 %

The portfolio is rebalanced on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust’s exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors’ investment style. The goal of the trust is to provide a rate of return consistently from three to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class	Comparative Benchmark(s)
Fixed Income	Lehman Aggregate Index
Equity Index	S&P 500 Index
Value Equity	Russell 1000 Value Index – Short-term
	S&P 500 Index – Long-term
Growth Equity	Russell 1000 Growth Index – Short-term
	S&P 500 Index – Long-term
Mid-Cap Equity	S&P 400 Midcap Index
Small-Cap Equity	Russell 2000 Index
International Equity	Morgan Stanley Capital International Europe, Australia and Far East Index

The fixed income manager is expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody’s Investors Service (“Moody’s”), Standard & Poor’s Ratings Services (“Standard & Poor’s”) or Fitch Ratings (“Fitch”). The portfolio may invest up to 10 percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of the Company’s equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the S&P 400 Midcap Index, small dividend yield, return on equity at or near the S&P 400 Midcap Index and earnings per share growth rate at or near the S&P 400 Midcap Index. The domestic small-capitalization equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International Europe, Australia and the Far East Index (“EAFE”) is the benchmark for comparative performance purposes. The EAFE Index is a market value weighted index comprised of over 1,000 companies traded on the stock markets of Europe, Australia, New Zealand and the Far East. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) after accounting for price appreciation. A minimum of 95 percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Options or financial futures may not be purchased unless prior approval of the Investment Committee is received. The purchase of securities on margin is prohibited as is securities

lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company’s equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager’s organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

Restoration of Retirement Income Plan

The Company provides a restoration of retirement income plan to those participants in the Company’s pension plan whose benefits are subject to certain limitations under the Internal Revenue Code (the “Code”). The benefits payable under this restoration of retirement income plan are equivalent to the amounts that would have been payable under the pension plan but for these limitations. The restoration of retirement income plan is intended to be an unfunded plan.

The Company expects to pay benefits related to its pension plan and restoration of retirement income plan of approximately $57.9 million in 2008, $58.9 million in 2009, $59.4 million in 2010, $62.5 million in 2011, $63.9 million in 2012 and an aggregate of approximately $289.7 million in years 2013 to 2017. These expected benefits are based on the same assumptions used to measure the Company’s benefit obligation at the end of the year and include benefits attributable to estimated future employee service.

Postretirement Benefit Plans

In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for eligible retired members (“postretirement benefits”). Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained age 55 with 10 years of vesting service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000, are not entitled to postretirement medical benefits. All regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with five years of vesting service at the time of retirement are entitled to postretirement life insurance benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges to expense the SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions,” costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

At December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s postretirement benefit plans was approximately $216.8 million and $78.5 million, respectively, for an underfunded status of approximately $138.3 million. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E’s portion which is recorded as a regulatory asset as discussed in Note 1) in the Company’s Consolidated Balance Sheet. The amount in Accumulated Other Comprehensive Loss and as a regulatory asset represents a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods.

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

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 9.0 percent in 2008 with the rates decreasing in subsequent years by one percentage point per year through 2011. A one-percentage point change in the assumed health care cost trend rate would have the following effects:

ONE-PERCENTAGE POINT INCREASE
Year ended December 31(In millions)	2007	2006	2005
Effect on aggregate of the service and interest cost components	$ 2.3	$ 2.2	$ 1.8
Effect on accumulated postretirement benefit obligations	26.9	29.2	26.9

ONE-PERCENTAGE POINT DECREASE
Year ended December 31(In millions)	2007	2006	2005
Effect on aggregate of the service and interest cost components	$ 1.9	$ 1.8	$ 1.5
Effect on accumulated postretirement benefit obligations	22.2	24.0	22.0

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare PrescriptionDrug, Improvement and Modernization Act of 2003.” FAS 106-2 provided guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also required those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The Company adopted this new standard effective July 1, 2004 with retroactive application to the date of the Medicare Act’s enactment. Management expects that the accumulated plan benefit obligation (“APBO”) for the Company with respect to its postretirement medical plan will be reduced by approximately $39.8 million as a result of savings to the Company with respect to its postretirement medical plan resulting from the Medicare Act provided subsidy, which will reduce the Company’s costs for its postretirement medical plan by approximately $5.5 million annually. The $5.5 million in annual savings is comprised of a reduction of approximately $2.6 million from amortization of the $39.8 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $2.3 million and a reduction in the service cost due to the subsidy of approximately $0.6 million.

The Company expects to pay gross benefits payments related to its postretirement benefit plans, including prescription drug benefits, of approximately $11.9 million in 2008, $13.0 million in 2009, $14.1 million in 2010, $15.2 million in 2011, $16.1 million in 2012 and an aggregate of approximately $92.3 million in years 2013 to 2017. The Company expects to receive federal subsidy receipts provided by the Medicare Act of approximately $1.3 million in 2008, $1.5 million in 2009, $1.6 million in 2010, $1.8 million in 2011, $1.9 million in 2012 and an aggregate of approximately $11.6 million in years 2013 to 2017. The Company received approximately $1.9 million in federal subsidy receipts in 2007.

Obligations and Funded Status

The details of the funded status of the pension plan (including the restoration of retirement income plan) and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are as follows:

			Restoration of Retirement			Postretirement
	Pension Plan		Income Plan			Benefit Plans
December 31 (In millions)	2007	2006	2007	2006		2007	2006

Change in Benefit Obligation
Beginning obligations	$ (575.2)	$ (584.4)	$ (9.8)	$ (9.6)		$ (225.4)	$ (208.2)
Service cost	(20.6)	(19.7)	(0.6)	(0.7)		(4.0)	(3.7)
Interest cost	(31.8)	(30.3)	(0.5)	(0.5)		(12.4)	(11.9)
Plan changes	16.7	---	0.1	---		---	---
Participants’ contributions	---	---	---	---		(5.5)	(5.0)
Actuarial gains (losses)	15.4	(15.5)	(1.4)	0.6		15.2	(12.1)
Benefits paid	77.5	74.7	8.2	0.4		15.3	15.5
Ending obligations	(518.0)	(575.2)	(4.0)	(9.8)		(216.8)	(225.4)

Change in Plans’ Assets
Beginning fair value	519.4	439.4	---		---	74.0	67.2
Actual return on plans’ assets	22.3	64.7	---		---	5.6	8.4
Employer contributions	50.0	90.0	8.2		0.4	8.7	8.9
Participants’ contributions	---	---	---		---	5.5	5.0
Benefits paid	(77.5)	(74.7)	(8.2)		(0.4)	(15.3)	(15.5)
Ending fair value	514.2	519.4	---		---	78.5	74.0
Funded status at end of year	$ (3.8)	$ (55.8)	$ (4.0)		$ (9.8)	$ (138.3)	$ (151.4)

Net Periodic Benefit Cost

				Restoration of Retirement			Postretirement
	Pension Plan			Income Plan			Benefit Plans
Year ended December 31
(In millions)	2007	2006	2005	2007	2006	2005	2007	2006	2005
Service cost	$ 20.6	$ 19.7	$ 18.7	$ 0.6	$ 0.7	$ 0.4	$ 4.0	$ 3.7	$ 3.2
Interest cost	31.8	30.3	29.8	0.5	0.5	0.5	12.4	11.9	10.5
Return on plan assets	(43.9)	(38.4)	(34.2)	---	---	---	(5.9)	(5.6)	(5.5)
Amortization of transition
obligation	---	---	---	---	---	---	2.7	2.7	2.7
Amortization of net loss	10.5	16.5	14.4	0.2	0.2	0.3	6.1	8.7	5.0
Amortization of recognized
prior service cost	5.2	5.2	5.7	0.6	0.7	0.6	2.1	2.1	2.1
Settlement	16.7	17.1	---	2.3	---	---	---	---	---
Net periodic benefit cost (A)	$ 40.9	$ 50.4	$ 34.4	$ 4.2	$ 2.1	$ 1.8	$ 21.4	$ 23.5	$ 18.0

(A) Approximately $10.1 million of the net periodic benefit cost relates to OG&E’s Oklahoma jurisdictional portion, which has been recorded as a regulatory asset (see Note 1 for a further discussion). The capitalized portion of the net periodic pension benefit cost was approximately $5.5 million, $7.6 million and $9.3 million at December 31, 2007, 2006 and 2005, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $4.8 million, $5.0 million and $4.7 million at December 31, 2007, 2006 and 2005, respectively.

Rate Assumptions

	Pension Plan and			Postretirement
	Restoration of Retirement Income Plan			Benefit Plans
Year ended December 31	2007	2006	2005	2007	2006	2005
Discount rate	6.25%	5.75%	5.50%	6.25%	5.75%	5.50%
Rate of return on plans’ assets	8.50%	8.50%	8.50%	8.50%	8.50%	8.50%
Compensation increases	4.50%	4.50%	4.50%	4.50%	4.50%	4.50%
Assumed health care cost trend:
Initial trend	N/A	N/A	N/A	9.00%	9.00%	9.00%
Ultimate trend rate	N/A	N/A	N/A	4.50%	4.50%	4.50%
Ultimate trend year	N/A	N/A	N/A	2013	2012	2011

N/A - not applicable

The overall expected rate of return on plan assets assumption remained at 8.50 percent in 2006 and 2007 in determining net periodic benefit cost. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the pension plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans’ current and expected asset allocation.

Post-Employment Benefit Plan

Disabled employees receiving benefits from the Company’s Group Long-Term Disability Plan are entitled to continue participating in the Company’s Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company’s Group Long-Term Disability Plan and their dependents, as defined in the Company’s Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company’s Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. The Company’s post-employment benefit obligation was approximately $1.6 million and $2.0 million at December 31, 2007 and 2006, respectively.

Defined Contribution Plan

The Company provides a defined contribution savings plan. Each regular full-time employee of the Company or a participating affiliate is eligible to participate in the plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the plan after completing one year of service as defined in the plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the plan, for that pay period. Contributions of the first six percent of compensation are called “Regular Contributions” and any contributions over six percent of compensation are called “Supplemental Contributions.” Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as “Catch-Up Contributions,” subject to the limitations of the Code. The Company contributes to the plan each pay period on behalf of each participant an amount equal to 50 percent of the participant’s Regular Contributions for participants whose employment or re-employment date, as defined in the plan, occurred before February 1, 2000 and who have less than 20 years of service, as defined in the plan, and an amount equal to 75 percent of the participant’s Regular Contributions for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service. For participants whose employment or re-employment date occurred on or after February 1, 2000, the Company contributes 100 percent of the Regular Contributions deposited during such pay period by such participant. No Company contributions are made with respect to a participant’s Supplemental Contributions, Catch-Up Contributions, or with respect to a participant’s Regular Contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. The Company’s contribution, which is initially allocated for investment to the OGE Energy Corp. Common Stock Fund, may be made in shares of the Company’s common stock or in cash which is used to invest in the Company’s common stock. Once made, the Company’s contribution may be reallocated, at any time, by participants to other available investment options. The Company contributed approximately $7.6 million, $6.8 million and $6.7 million during 2007, 2006 and 2005, respectively, to the defined contribution plan.

Deferred Compensation Plan

The Company provides a deferred compensation plan. The plan’s primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees’ defined contribution plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of bonus awards; or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the defined contribution plan with such deferrals to start when maximum deferrals to the qualified defined contribution plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors’ meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to provide for the match that would have been made under the defined contribution plan had such deferrals been made under that plan without regard to the statutory limitations on elective deferrals and matching contributions applicable to the defined contribution plan. In addition, the Benefits Committee may award discretionary employer contribution credits to a participant under the plan. The Company accounts for the contributions related to the Company’s executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company’s directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.

Supplemental Executive Retirement Plan

The Company provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of the Company’s Board of Directors who may not otherwise qualify for a sufficient level of benefits under the Company’s pension plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the Code.

15.

Report of Business Segments

Historically, the Company’s business was divided into two reportable segments, electric utility and natural gas pipeline. As part of the process of preparing the registration statement on Form S-1 for the Partnership that was filed on June 27, 2007 and as discussed in Note 1, the Company determined that, for reporting purposes, Enogex, as a stand-alone entity, has historically had three segments – (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Beginning with the second quarter of 2007, the Company’s business is now divided into four reportable segments for reporting purposes. These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. As discussed in Note 1, on January 1, 2008, Enogex distributed the stock of OERI, which engages in the marketing of natural gas, to OGE Energy. Other Operations for the years ended December 31, 2007 and 2006 primarily included consolidating eliminations. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and therefore has presented this information below. The following tables summarize the results of the Company’s business segments for the years ended December 31, 2007, 2006 and 2005. The results of the Company’s business segments have been restated for all prior periods presented to conform to the 2007 presentation.

Transportation

Gathering

Electric

and

Other

2007

Utility

Storage

Processing

Marketing

Operations

Eliminations

Total

(In millions)

Operating revenues

1,835.1

230.4

799.4

1,537.9

---

(605.2)

3,797.6

Cost of goods sold

1,025.1

97.7

603.5

1,513.4

---

(605.0)

2,634.7

Gross margin on revenues

810.0

132.7

195.9

24.5

---

(0.2)

1,162.9

Other operation and maintenance

320.7

48.5

72.1

6.8

(11.3)

---

436.8

Depreciation

141.3

17.0

28.7

0.2

8.1

---

195.3

Impairment of assets

---

0.5

---

0.5

Taxes other than income

56.0

11.7

3.7

0.4

3.2

---

75.0

Operating income

292.0

55.0

91.4

17.1

---

(0.2)

455.3

Total assets

3,874.9

1,519.3

931.4

253.2

2,297.6

(3,638.6)

5,237.8

Capital expenditures

377.3

49.0

125.0

0.2

14.5

(8.3)

557.7

			Transportation		Gathering
	Electric		and		and				Other
2006	Utility		Storage		Processing		Marketing		Operations		Eliminations		Total
(In millions)

Operating revenues	$	1,745.7	$	225.9	$	704.3	$	1,941.3	$	---	$	(611.6)	$	4,005.6
Cost of goods sold		950.0		100.3		536.7		1,927.1		---		(611.6)		2,902.5
Gross margin on revenues		795.7		125.6		167.6		14.2		---		---		1,103.1
Other operation and maintenance		316.5		41.2		59.5		9.3		(9.9)		---		416.6
Depreciation		132.2		17.9		24.2		0.2		6.9		---		181.4
Impairment of assets		---		---		0.3		---		---		---		0.3
Taxes other than income		53.1		11.8		3.8		0.4		3.0		---		72.1
Operating income	$	293.9	$	54.7	$	79.8	$	4.3	$	---	$	---	$	432.7
Total assets	$	3,589.7	$	1,441.2	$	843.7	$	231.4	$	1,968.8	$	(3,176.4)	$	4,898.4
Capital expenditures	$	411.1	$	9.8	$	57.6	$	---	$	8.4	$	(0.3)	$	486.6

			Transportation		Gathering
	Electric		and		and		Marketing		Other
2005	Utility		Storage		Processing		(A)		Operations		Eliminations		Total
(In millions)

Operating revenues	$	1,720.7	$	246.4	$	644.5	$	3,995.3	$	---	$	(695.4)	$	5,911.5
Cost of goods sold		994.2		147.3		504.3		3,992.6		---		(696.1)		4,942.3
Gross margin on revenues		726.5		99.1		140.2		2.7		---		0.7		969.2
Other operation and maintenance		309.2		32.9		55.3		8.4		(10.9)		---		394.9
Depreciation		134.4		17.3		23.0		0.1		7.8		---		182.6
Taxes other than income		50.7		11.6		3.4		0.4		3.2		---		69.3
Operating income (loss)	$	232.2	$	37.3	$	58.5	$	(6.2)	$	(0.1)	$	0.7	$	322.4
Total assets	$	3,255.0	$	1,456.9	$	729.0	$	525.4	$	1,963.4	$	(3,058.3)	$	4,871.4
Capital expenditures	$	249.1	$	9.2	$	25.6	$	---	$	13.4	$	(0.1)	$	297.2

(A) In March 2005, OERI corrected its procedure for accounting for park and loan transactions (natural gas storage transactions) during 2004 that resulted from an incorrect change in an accounting procedure implemented during 2004. The incorrect procedure affected the timing of recognition of revenue and income from park and loan transactions and resulted in a temporary overstatement of operating revenues without the associated expense until the transaction was completed and the expense recognized. As a result of this correction, OERI recorded a pre-tax charge of approximately $7.7 million ($4.7 million after tax or $0.05 per share) as a reduction in Operating Revenues in the Consolidated Statement of Income and a corresponding $7.7 million decrease in Current Price Risk Management Assets in the Consolidated Balance Sheet during the three months ended March 31, 2005.

16.

Commitments and Contingencies

Operating Lease Obligations

The Company has operating lease obligations expiring at various dates, primarily for OG&E railcar leases and Enogex noncancellable operating leases. Future minimum payments for noncancellable operating leases are as follows:

						2013 and
Year ended December 31 (In millions)	2008	2009	2010	2011	2012	Beyond

Operating lease obligations
OG&E railcars	$ 3.7	$ 3.7	$ 3.6	$ 34.9	$ ---	$ ---
Enogex noncancellable operating leases	1.9	1.8	1.6	1.5	0.4	---
Total operating lease obligations	$ 5.6	$ 5.5	$ 5.2	$ 36.4	$ 0.4	$ ---

Payments for operating lease obligations were approximately $6.7 million, $7.6 million and $9.7 million in 2007, 2006 and 2005, respectively.

OG&E Railcar Lease Agreement

At December 31, 2007, OG&E had a noncancellable operating lease with purchase options, covering 1,409 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. On December 29, 2005, OG&E entered into a new lease agreement for railcars effective February 1, 2006 with a new lessor as described below. At the end of the new lease term, which is January 31, 2011, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of approximately $28.8 million. 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.

Public Utility Regulatory Policy Act of 1978

OG&E has entered into agreements with three qualifying cogeneration facilities having initial terms of three to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978 (“PURPA”). Stated generally, PURPA and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). See Note 17 for discussion of a recent FERC ruling related to QF obligations. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E’s obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. OG&E had a QF contract for approximately 110 MWs that expired at the end of 2007 and was not extended by OG&E. For the AES-Shady Point, Inc. (“AES”) QF contract for 320 MWs, OG&E purchases 100 percent of the electricity generated by the QF. In addition, effective September 1, 2004, OG&E entered into a new 15-year power purchase agreement for 120 MWs with Powersmith Cogeneration Project, L.P. (“PowerSmith”) in which OG&E purchases 100 percent of electricity generated by PowerSmith.

During 2007, 2006 and 2005, OG&E made total payments to cogenerators of approximately $156.8 million, $162.6 million and $183.8 million, respectively, of which approximately $88.9 million, $94.9 million and $95.5 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Goods Sold. The future minimum capacity payments under the contracts are approximately: 2008 – $88.4 million, 2009 – $86.8 million, 2010 – $85.0 million, 2011 – $83.1 million and 2012 – $81.0 million.

Fuel Minimum Purchase Commitments

OG&E purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $190.2 million, $195.1 million and $163.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. OG&E has entered into purchase commitments of necessary fuel supplies of approximately: 2008 – $115.1 million, 2009 – $110.2 million, 2010 – $114.3 million, 2011 – $65.3 million, 2012 – $4.0 million and 2013 and Beyond – $19.6 million.

Natural Gas Units

In August 2007, OG&E issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2007 through March 2008, which accounted for approximately 15 percent of its projected 2008 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices and will expire in 2008. Additional gas supplies to fulfill OG&E’s remaining 2008 natural gas requirements will be acquired through additional RFPs in early to mid-2008, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.

Purchased Power

In March 2007, OG&E issued an RFP for capacity and/or firm energy purchases for the summer periods of 2008, 2009 and/or 2010. In November 2007, OG&E signed a purchase contract with Redbud for purchases in the summer periods of 2008 and 2009. OG&E submitted notice of the contract to the OCC on January 2 and 3, 2008. Interventions and protests were due within 15 days of submission of the notice. No interventions or protests were received in this matter and OG&E considers this purchase contract to be final. The purchase contract will be terminated if the acquisition of Redbud by OG&E, the OMPA and the GRDA is completed as discussed in Note 17.

Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C.

Cheyenne Plains Gas Pipeline Company, L.L.C. (“Cheyenne Plains”) operates the Cheyenne Plains Pipeline that provides firm transportation services in Wyoming, Colorado and Kansas with a capacity of 730,000 decatherms/day (“Dth/day”). OERI entered into a Firm Transportation Service Agreement (“FTSA”) with Cheyenne Plains in 2004, for 60,000 Dth/day of firm capacity on the Cheyenne Plains Pipeline. The FTSA was for a 10-year term beginning with the in-service date of the Cheyenne Plains Pipeline in March 2005 with an annual demand fee of approximately $7.4 million. Effective March 1, 2007, OERI and Cheyenne Plains amended the FTSA to provide for OERI to turn back 20,000 Dth/day of its capacity beginning in January 2008 for the remainder of the term. OERI’s new demand fee obligations, net of this turn back and other immaterial release agreements, are estimated at approximately $5.9 million in 2008; $6.5 million for each of the years 2009 through 2014; and $1.6 million in 2015.

Agreement with Midcontinent Express Pipeline, LLC

In December 2006, Enogex entered into a firm capacity lease agreement with Midcontinent Express Pipeline, LLC (“MEP”) for a primary term of 10 years (subject to possible extension) that would give MEP and its shippers access to capacity on Enogex’s system. The quantity of capacity subject to the MEP lease agreement is currently 275 million cubic feet per day, with the quantity ultimately to be leased subject to being increased by mutual agreement pursuant to the lease agreement. In addition to MEP’s lease of Enogex’s capacity, the proposed MEP project includes construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Pending necessary regulatory approval, the MEP project is currently expected to be in service during the first quarter of 2009. Enogex currently estimates that its capital expenditures related to this project will be approximately $86 million. The lease agreement with MEP is subject to certain contingencies, including regulatory approval. Prior to that approval, Enogex may incur expenditures of between approximately $20 million and $40 million primarily related to commitments for materials that can be sold or used in normal operations in the event the MEP project does not proceed. The amount not recovered or utilized for such expenditures is not expected to be material.

MEP filed an application with the FERC on October 9, 2007 requesting a certificate of public convenience and necessity authorizing MEP to construct its pipeline and lease certain capacity from Enogex. On October 9, 2007, Enogex also filed an application with the FERC for issuance of a limited jurisdiction certificate authorizing its lease agreement with MEP. Certain Enogex shippers have filed motions to intervene in Enogex’s FERC certificate proceeding, and some have protested Enogex’s certificate application. Protestors have claimed that it is unduly discriminatory for Enogex to propose to lease capacity to MEP while not generally offering firm interstate transportation service, that the lease arrangement will adversely affect the availability of interruptible interstate transportation service on the Enogex system and that the lease payment specified under the MEP lease agreement is unduly preferential in MEP’s favor. These protestors have urged the FERC to reject the MEP lease arrangement or to condition its acceptance on a requirement that Enogex offer existing shippers taking interruptible interstate service the opportunity to convert that service to firm service. One protestor has asked the FERC to consolidate the Enogex certificate proceeding with Enogex’s Section 311 triennial rate proceeding currently pending before the FERC. While Enogex cannot predict what action the FERC may take regarding the lease agreement, Enogex believes that the proposed MEP lease arrangement is consistent with FERC policy and precedent involving similar lease arrangements.

Natural Gas Measurement Cases

United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit (“Btu”) content) purchased from federal and Indian lands which have resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In qui tam actions, the Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.

The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and

consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming.

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that OG&E and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and OG&E, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees on various bases January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, the Company filed a notice of its intent to file a separate response brief, which the Company filed on January 11, 2008. At this time, oral arguments are preliminarily scheduled for the week of September 22, 2008. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of the Company’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of the Company’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of the Company filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.

The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II). On May 12, 2003, the plaintiffs (same as those in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the amended petition of the Price I case. The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

Farris Buser Litigation

On July 22, 2005, Enogex along with certain other unaffiliated co-defendants was served with a purported class action which had been filed on February 7, 2005 by Farris Buser and other named plaintiffs in the District Court of Canadian County, Oklahoma. The plaintiffs own royalty interests in certain oil and gas producing properties and allege they have been under-compensated by the named defendants, including Enogex and its subsidiaries, relating to the sale of liquid hydrocarbons recovered during the transportation of natural gas from the plaintiffs’ wells. The plaintiffs assert breach of contract, implied covenants, obligation, fiduciary duty, unjust enrichment, conspiracy and fraud causes of action and claim actual damages in excess of $10,000, plus attorneys’ fees and costs, and punitive damages in excess of $10,000. Enogex and its subsidiaries filed a motion to dismiss which was granted on November 18, 2005, subject to the plaintiffs’ right to conduct discovery and the possible re-filing of their allegations in the petition against the Enogex companies. On September 19, 2005, the co-defendants, BP America, Inc. and BP America Production Co. (collectively, “BP”), filed a cross claim against Products seeking indemnification and/or contribution from Products based upon the 1997 sale of a third-party interest in one of Products natural gas processing plants. On May 17, 2006, the plaintiffs filed an amended petition against Enogex and its subsidiaries. Enogex and its subsidiaries filed a motion to dismiss the amended petition on August 2, 2006. The hearing on the dismissal motion was held on November 20, 2006 and the court denied Enogex’s motion. Enogex filed an answer to the amended petition and BP’s cross claim on January 16, 2007. Based on Enogex’s investigation to date, the Company believes these claims and cross claims in this lawsuit are without merit and intends to continue vigorously defending this case.

Calpine Corporation Bankruptcy

Calpine Corporation, Calpine Energy Services, L.P., and several other affiliates (collectively “Calpine”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on December 20, 2005 (Case No. 05-60200 (BRL)) in the United States Bankruptcy Court, Southern District of New York (the “Bankruptcy Court”). Enogex provides natural gas transportation services pursuant to long-term contracts to two Calpine-owned power generation plants in Oklahoma. Calpine is continuing to operate the plants and request services pursuant to the contracts. The total unpaid amount due to Enogex from Calpine totaled approximately $0.3 million, which was fully reserved on the Company’s books.

During October 2007, Calpine and Enogex agreed to and executed amended and restated contracts extending the primary terms, reducing the volume of firm transportation and including authorized overrun charges for additional capacity utilized. As part of the agreements, approximately $0.2 million of the bankruptcy claim was paid in November 2007 and the remaining $0.1 million will be allowed as a general unsecured claim and a cure amount under the bankruptcy plan. The amended and restated contracts were presented to and approved by the Bankruptcy Court on October 19, 2007 and the order became final on October 30, 2007. The payment of the remaining claims ($0.1 million) is currently fully reserved and is expected to be paid in the first quarter of 2008.

A Calpine-owned power generation plant in Oklahoma is contractually obligated to provide capacity and energy to OG&E; however, the contract terminated on December 31, 2007. The Calpine plant also pays, through the SPP, for transmission services provided by OG&E. Whether Calpine will subsequently continue to require transmission services from OG&E is unknown.

OERI Self-Disclosure Matter

On November 13, 2007, OERI orally self-reported to the FERC Office of Enforcement (“OE”) a certain 2005 three-month transaction that occurred in 2005 (“Transaction”) between OERI and an unaffiliated third party. OERI reported, based on its initial findings, that the Transaction may have violated the FERC’s shipper-must-have-title policy and the maximum rate cap applicable to natural gas transportation. OERI conducted an internal investigation (“Internal Investigation”) into the Transaction and on December 18, 2007, at OE’s request, OERI provided a written report to the OE of that Internal

Investigation. By letter dated December 20, 2007, OE advised OERI that it had commenced a preliminary, non-public investigation into compliance matters relating to the Transaction. On February 7, 2008, the OE submitted to OERI discovery requests relating to various aspects of the Transaction and Internal Investigation. OERI responded to the discovery requests on February 28, 2008. OERI will supplement the written report of its Internal Investigation, if necessary, to address any other similar transactions or practices that it may identify as raising potential compliance issues in the course of its Internal Investigation.

The FERC has imposed substantial civil penalties on entities subject to its jurisdiction that violate provisions of the Natural Gas Act. Some self-reports to OE have resulted in settlements requiring the entities to pay significant civil penalties, whereas others have been concluded without a penalty payment or any other remedial measures being required. At this time the Company cannot determine or predict either the timing of the completion or the final outcome of OE’s investigation of the OERI self-report.

Potential Collateral Requirements

In the event Moody’s or Standard & Poor’s were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, at December 31, 2007, Enogex would have been required to post approximately $26.3 million of collateral to satisfy its obligation under its financial and physical contracts.

Environmental Laws and Regulations

Approximately $36.9 million and $121.4 million, respectively of the Company’s capital expenditures budgeted for 2008 and 2009 are to comply with environmental laws and regulations. The Company’s management believes that all of its operations are in substantial compliance with present federal, state and local environmental standards. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $99.2 million during 2008 as compared to approximately $68.4 million in 2007. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market.

OG&E

Air

On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule. One possible consequence is that the EPA will develop regulations that are more stringent than the CAMR and the trading of mercury allowances will not be allowed. Until the rule was vacated, the CAMR required mercury monitoring to begin in 2009. Accordingly, OG&E is in the process of installing mercury monitoring equipment on all five of its coal units. The cost of the monitoring equipment was approximately $5.0 million in 2007 and OG&E expects to spend approximately $0.7 million in 2008. Because the CAMR was vacated, the cost to install additional mercury controls is uncertain at this time but may be significant, particularly if the EPA develops more stringent requirements. The outcome of the CAMR ruling does not preclude states from developing more stringent mercury reduction requirements. In 2006, the State of Oklahoma proposed to incorporate the EPA’s CAMR, along with the proposed mercury allowance allocations, into the state implementation program. In January 2008, in response to citizen requests, the Oklahoma Department of Environmental Quality (“ODEQ”) proposed three options for regulation of mercury emissions. As initially proposed, one option recommended by the ODEQ Staff was that the CAMR be incorporated by reference into the state implementation plan. The other two options are intended to be more restrictive than the recently vacated federal CAMR. In general, the proposed options include provisions that mercury trading will not be allowed, higher levels of mercury control will be required and compliance timelines may be shortened in comparison with the CAMR Promulgation of an Oklahoma rule may be further delayed if the ODEQ decides to wait for the EPA to re-promulgate a federal mercury rule. OG&E will continue to participate in the state rule making process.

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the regulation. However, Oklahoma’s impact on parks in other states must also be evaluated. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. The State of Oklahoma has joined with eight other central states to address these visibility impacts.

In September 2005, the ODEQ informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have “Best Available Retrofit Technology (“BART”) eligible sources” (sources built between 1962 and 1977). For OG&E, these include various generating units at various generating stations. Regulations, however, allow an owner or operator of a BART-eligible source to request and obtain a waiver from BART if modeling shows no significant impact on visibility in nearby Class I areas. Based on this modeling, the ODEQ made a preliminary determination to accept an application for a waiver for the Horseshoe Lake generating station. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan. The due date for the ODEQ submission of the state implementation plan was December 17, 2007; however, the ODEQ has not yet submitted a plan to the EPA for approval. It is not known whether approval for the state implementation plan will be granted by the EPA.

The modeling did not support waivers for the affected units at the Seminole, Muskogee and Sooner generating stations. OG&E submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, OG&E submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants will achieve overall greater visibility improvement than BART in the affected Class I areas and the alternative plan extends the timeline for compliance to 2018. The estimated cost for this alternative plan and the BART compliance plan for the Seminole power plant is approximately $470 million. The alternative compliance plan includes installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan was subject to approval by the ODEQ and the EPA. The EPA provided an opinion to the ODEQ that OG&E’s alternative compliance plan does not meet the requirements of the regional haze rules. On November 16, 2007, the ODEQ notified OG&E that additional analysis will be required before the OG&E BART plan can be accepted. As required by the ODEQ, OG&E has initiated the additional analysis with a projected completion date of March 1, 2008. Until a compliance plan has been approved by the EPA, which is expected by December 31, 2008, the annual cost of compliance remains unknown at this time. The cost to comply with the regional haze regulations could increase substantially based on the interpretation of the requirements by the ODEQ and the EPA, the availability of alternative control measures to achieve more cost effective visibility improvements, the availability of materials, labor force and the specific design criteria for OG&E’s generating units. OG&E expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E’s retail customers under House Bill 1910, which was enacted into law in May 2005.

With respect to the NOX regulations of the acid rain program, OG&E committed to meeting a 0.45 lbs/million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a result, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E’s average NOX emissions from its coal-fired boilers for 2007 were approximately 0.32 lbs/MMBtu. The regulations require that OG&E achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers beginning in 2008. It is expected that NOX emissions will be further reduced to 0.15 lbs/MMBtu by 2016 if the regional haze compliance plan discussed above is approved by the EPA. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are impacting the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma becomes non-attainment with the fine particulate standard. Any of these scenarios would likely require significant capital and operating expenditures.

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone. However, future elevated readings could lead to redefinition of these areas as non-attainment. Both Tulsa and Oklahoma City have entered into an “Early Action Compact” with the EPA whereby voluntary measures are required to be enacted to reduce the impact of ambient levels of ozone. This compact expired in December 2007. However, a similar program called Ozone Flex began in January 2008 in which both Oklahoma City and Tulsa are participating. Currently, the EPA is reevaluating the current ozone standard and proposed further reductions in the ambient standard on September 20, 2007. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.

On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Clean Air Act as a result of the adoption of the revised ambient ozone and fine particle standards. Failure to submit these implementation plans began a two-year timeframe, starting on May 25, 2005, during which states must submit a demonstration to the EPA that they do not affect air quality in downwind states. Earlier in 2005 it was unclear whether this could be accomplished by the State of Oklahoma and it was previously reported that there may be future significant expenditures required by OG&E if Oklahoma was determined to impact the air quality in downwind states. However, recent communications with the State of Oklahoma have affirmed that they have completed this demonstration and Oklahoma does not affect air quality in downwind states. The demonstration was properly submitted by the state to the EPA on May 7, 2007, and additional information was submitted by the state to EPA on December 5, 2007. Assuming the state

implementation plan is approved as submitted, there should be no significant adverse impact to OG&E as a result of the April 25, 2005 finding. The date of EPA approval is currently unknown.

On September 21, 2006, the EPA lowered the 24-hour fine particulate ambient standard while retaining the annual standard at its current level and promulgated a new standard for inhalable coarse particulates. Based on past monitoring data, it appears that Oklahoma may be able to remain in attainment with these standards. However if parts of Oklahoma do become “non-attainment”, reductions in emissions from OG&E’s coal-fired boilers could be required which may result in significant capital and operating expenditures.

The 1990 Clean Air Act includes an acid rain program to reduce sulfur dioxide (“SO2”) emissions. Reductions were obtained through a program of emission (release) allowances issued by the EPA to power plants covered by the acid rain program. Each allowance is worth one ton of SO2 released from the chimney. Plants may only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide. Beginning in 2000, OG&E became subject to more stringent SO2 emission requirements in Phase II of the acid rain program. These lower limits had no significant financial impact due to OG&E’s earlier decision to burn low sulfur coal. In 2007, OG&E’s SO2 emissions were below the allowable limits.

The EPA allocated SO2 allowances to OG&E starting in 2000 and OG&E started banking allowances in 2001. OG&E sold no banked allowances in 2007. Also, during 2007, OG&E received proceeds of approximately $0.5 million from the annual EPA spot (year 2007) and seven-year advance (year 2014) allowance auctions that were held in March 2007.

The ODEQ Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, OG&E had submitted all required permit applications. As of December 31, 2007, OG&E had received Title V permits for all of its generating stations. Since these permits require renewal every five years, OG&E has begun the renewal process for some of its generating stations. Air permit fees for generating stations were approximately $0.6 million in 2007. In January 2008, the ODEQ proposed fee increases of approximately 28 percent for Title V sources. These fee increases were approved by the Oklahoma Air Quality Council on February 5, 2008. The final outcome of this measure is dependent upon approval by the ODEQ Board and the Oklahoma state legislature. If approved, the fee increases will be effective July 1, 2008.

In addition to the requirements related to emissions of SO2, NOX and mercury discussed above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.

On the legislative front, in June 2005, the U.S. Senate adopted a resolution declaring that mandatory reductions in greenhouse gases are needed. Despite executive branch opposition to any mandatory requirements, several bills that would cap or tax greenhouse gases from electric utilities are being considered by Congress, and the concept of such regulation has received support from the majority leadership in both the U.S. Senate and U.S. House of Representatives.

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and federal action on climate change issues. OG&E reports quarterlyits carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Waste

OG&E has sought and will continue to seek, new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2007, OG&E obtained refunds of approximately $1.0 million from its recycling efforts. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

Water

OG&E received two Oklahoma Pollutant Discharge Elimination System (“OPDES”) permits in February 2008. OG&E is currently reviewing these permits to determine if they are reasonable in their requirements, allow operational flexibility and provide reductions in operating costs. Additionally, OG&E filed an application with the State of Oklahoma during 2006 for a new wastewater discharge permit for one of its facilities. This new permit was issued in the fourth quarter of 2007.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA Section 316(b) rules for existing facilities became effective July 23, 2004. OG&E has engaged a consultant who has developed the required documentation for four OG&E facilities. These documents were submitted to the state agency on December 7, 2005 for review and approval. OG&E has also provided the State of Oklahoma with information and requests that, if approved by the state, may reduce the impact of the Section 316(b) rules on OG&E. On January 25, 2007, a federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the State of Oklahoma indicated that it was requiring a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility. On January 7, 2008, OG&E submitted the requested studies for its facilities. It is not clear what changes, if any, the EPA will ultimately make to the Section 316(b) rules or how those changes may affect OG&E. Depending on the ultimate analysis and final determinations regarding the Section 316(b) rules and the Oklahoma comprehensive demonstration studies, capital and/or operating costs may increase at any affected OG&E generating facility.

Enogex

The construction and operation of pipelines, plants and other facilities for transporting, processing, compressing or storing natural gas and other products are subject to stringent and complex federal, state and local laws and regulations, governing environmental protection as well as the discharge of materials into the environment. These laws and regulations can restrict or impact Enogex’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment. Enogex handles some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Clean Water Act and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes.

Environmental regulation can increase the cost of planning, design, initial installation and operation of Enogex’s facilities. Historically, Enogex’s total expenditures for environmental control facilities and for remediation have not been significant in relation to its consolidated financial position or results of operations. The Company believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards may incrementally increase the cost of conducting business.

The Company has and will continue to evaluate the impact of its operations on the environment. As a result, contamination on Company property may be discovered from time to time.

Air

standard and proposed further reductions in the ambient standard on September 20, 2007. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.

The ODEQ Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. As of December 31, 2007, Enogex had received all required Title V permits and intends to continue to renew these permits as necessary. Environmental permits and fees for Enogex facilities were approximately $0.2 million in 2007. The fees for 2008 are projected to be approximately 23 percent higher than the 2007 fees. In January 2008, the ODEQ proposed fee increases of approximately 28 percent for Title V sources and 13 percent for minor sources. These fee increases were approved by the Oklahoma Air Quality Advisory Council on February 5, 2008. The final outcome of this measure is dependent upon approval by the ODEQ Board and the Oklahoma state legislature. If approved, the fee increases will be effective July 1, 2008.

There is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.

Oklahoma and Texas have not, at this time, established any mandatory programs to regulate greenhouse gases. However, government officials in these states have declared support for state and federal action on climate change issues. Enogex is a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of greenhouse gases to address climate change, this could have a significant impact on Enogex’s operations.

Other

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. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Consolidated Financial Statements. Except as otherwise stated above, in Note 17 below and in Item 3 of this Annual Report on Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

17.

Rate Matters and Regulation

Regulation and Rates

OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of OG&E’s facilities and operations. For the year ended December 31, 2007, approximately 87 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and four percent to the FERC.

The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC

deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

Completed Regulatory Matters

OCC Order Confirming Savings / Acquisition of McClain Power Plant

The 2002 Settlement Agreement required that, if OG&E did not acquire electric generation of not less than 400 MW (“New Generation”) by December 31, 2003, OG&E must credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. On July 9, 2004, OG&E completed the acquisition of the McClain Plant which was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire New Generation. On June 7, 2007, OG&E filed an application with the OCC supporting its compliance with the 2002 Settlement Agreement. On November 21, 2007, OG&E received an order from the OCC affirming that the acquisition of the McClain Plant provided savings to OG&E’s Oklahoma customers in excess of the required $75 million over the three-year period from January 1, 2004 through December 31, 2006.

Security Enhancements

OG&E filed an application with the OCC on December 15, 2006 to amend its security plan to seek approval of approximately $7.6 million of cost increases related to the expanded scope of previously authorized projects and approximately $10.9 million for new security projects with an associated annual revenue requirement of approximately $2.7 million. On June 26, 2007, the OCC issued an order approving approximately $17.6 million of security capital expenditures and the associated revenue requirement of approximately $2.6 million, which OG&E implemented during the first billing cycle of July 2007.

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2005

The OCC routinely audits activity in OG&E’s fuel adjustment clause for each calendar year. In October 2006, the OCC Staff filed an application for a review of OG&E’s 2005 fuel adjustment clause. In September 2007, the OCC issued an order approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2005.

Cogeneration Credit Rider

OG&E’s cogeneration credit rider was initially implemented in 2005 as part of the Oklahoma retail customer electric rates in order to return purchase power capacity payment reductions and any change in operating and maintenance expense related to cogeneration previously included in base rates to OG&E’s customers. The cogeneration credit rider was updated and approved by the OCC in December of each year through December 2006 and any over/under recovery of the cogeneration credit rider in the current year and prior periods was automatically included in the next year’s rider. OG&E filed an application with the OCC in September 2007 to request a new cogeneration credit rider for years after 2007 as OG&E’s current cogeneration credit rider expired on December 31, 2007. In December 2007, the OCC issued an order approving a cogeneration credit rider that expires on December 31, 2009.

OG&E Wind Power Filing

In January 2007, OG&E’s 120 MW Centennial wind farm was fully in service. As a result, on January 17, 2007, OG&E sent notice of this to the OCC which triggered the recovery rider in the first billing cycle of February 2007. The recovery rider, which was previously approved in an OCC settlement, authorized recovery for up to $205 million in construction costs and allowance for funds used during construction and was designed to recover the lower of a capped or actual revenue requirement including a return on equity of 10.75 percent. OG&E spent approximately $203.8 million related to the Centennial wind farm. OG&E expects the recovery rider to remain in effect through late 2009. As indicated in the settlement agreement with the OCC related to OG&E’s Centennial wind farm, OG&E must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009.

OG&E Arkansas Rate Case Filing

On July 28, 2006, OG&E filed with the APSC an application for an annual rate increase of approximately $13.5 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant, the Centennial wind power project and the costs of electric system expansion and upgrades based on a return on equity of 11.75 percent. On January 5, 2007, the APSC issued an order providing for a $5.4 million annual increase in OG&E’s electric rates, a 10.0

percent return on equity and the recovery of the Arkansas portion of the Centennial wind farm expenditures. The Arkansas rates became effective in February 2007.

OG&E FERC Audit

On May 29, 2006, the FERC notified OG&E that it was commencing an audit to determine whether and how OG&E is complying with: (i) its Open Access Transmission Tariff; (ii) requirements of its market-based rate authorization; (iii) Standards of Conduct and Open Access Same-Time Information System; and (iv) wholesale fuel adjustment clause tariff and other requirements contained in FERC regulations. Over the past several years, the FERC has conducted numerous audits of utilities across the country to ensure regulatory compliance. On June 29, 2007, the FERC issued its final audit report with a limited set of findings and recommended certain actions that OG&E has since implemented. Among its findings, the FERC concluded that OG&E did not make the appropriate refunds to certain wholesale customers subsequent to the OCC issuing an order changing the amount of storage costs in OG&E’s gas transportation and storage agreement with Enogex that are recoverable from Oklahoma retail customers. As a result, OG&E recomputed billings made after May 2003 to certain wholesale customers and issued refunds in accordance with FERC regulations. The total amount of the refunds was approximately $1.0 million, including interest, which OG&E had fully reserved on its books in December 2006.

Enogex FERC Audit

On May 29, 2007, the FERC notified Enogex that it was commencing an audit to determine whether and how Enogex is complying with periodic regulatory reporting requirements for intrastate pipelines. On the same day, the FERC notified a number of other intrastate pipelines and storage entities of comparable audits. In preparing for the audit, Enogex advised the FERC Staff that it had inadvertently failed to timely file three storage reports required under FERC regulations. Enogex promptly submitted those storage reports to the FERC. The FERC completed its audit of Enogex in September 2007 and approved the corrective actions taken by Enogex and determined that no further corrective action is required.

Southwest Power Pool

In February 2007, OG&E began participating in the SPP’s energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including OG&E, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ MWH entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Consolidated Financial Statements.

FERC Ruling under PURPA

On September 25, 2007, as amended on October 24, 2007, OG&E filed an application with the FERC seeking relief from its obligation to purchase electric energy and capacity from QFs with a net capacity greater than 20 MW as required by PURPA. The Energy Policy Act of 2005 established a process that allows utilities to terminate the mandatory purchase obligation in certain circumstances. In an order dated January 22, 2008, the FERC found that OG&E had met the aforementioned standard and granted OG&E’s request. The order does not affect OG&E’s existing QF contracts with AES and PowerSmith; however, it does grant OG&E an exemption from any purchase obligations otherwise arising under PURPA after the date of filing of OG&E’s application.

Pending Regulatory Matters

Proposed Acquisition of Power Plant

power generation facility in Luther, Oklahoma (“Redbud Facility”), for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.

In connection with the Purchase and Sale Agreement, OG&E also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the OMPA and the Grand River Dam Authority (“GRDA”), pursuant to which OG&E agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which OG&E, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and OG&E will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.

Cancelled Red Rock Power Plant

On October 11, 2007, the OCC issued an order denying OG&E and PSO’s request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Consolidated Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. OG&E expects to receive an order from the OCC in this matter by the end of 2008.

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2006

The OCC routinely audits activity in OG&E’s fuel adjustment clause for each calendar year. In September 2007, the OCC Staff filed an application for a prudence review of OG&E’s 2006 fuel adjustment clause. OG&E is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, OG&E requested and was granted an extension to file the MFRs by January 15, 2008, on which date the MFRs were submitted by OG&E. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for August 21, 2008. OG&E expects to receive an order from the OCC in this matter by the end of 2008.

OG&E FERC Formula Rate Filing

On November 30, 2007, OG&E made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on OG&E’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of OG&E’s filing. OG&E filed an answer to the OMPA’s protest on January 7, 2008. On January 31, 2008, the FERC issued an order (i) conditionally accepting the rates; (ii) suspending the effectiveness of such rates for five months, to be effective July 1, 2008, subject to

refund; (iii) establishing hearing and settlement judge procedures; and (iv) directing OG&E to make a compliance filing. The first settlement conference was held on February 20, 2008. Another settlement conference is scheduled for May 9, 2008.

Enogex FERC Section 311 2007 Rate Case

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for service in the East Zone and West Zone. Enogex’s filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some additionally filed protests. In the normal course of the triennial rate case, the FERC Staff and intervenors will serve data requests on Enogex with respect to the cost of service submitted with the filing in support of the proposed rates and the parties will, thereafter, undertake settlement discussions. There is no statutory deadline by which the FERC must act on the filing. The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action, as the FERC has done in past Enogex cases. The FERC Staff has served its initial data requests on Enogex and Enogex has submitted its responses. The parties are currently in settlement negotiations. The FERC Staff, Enogex and one intervenor have exchanged offers of settlement, but a settlement has not been reached. Enogex has not, as of yet, placed the increased rates into effect. Enogex must file its next rate case no later than October 1, 2010 to comply with the FERC’s requirement for triennial filings.

Enogex 2008 Fuel Filing

As required by the fuel tracker provisions of its Statement of Operating Conditions, Enogex files annually to update its fuel percentages. In the settlement of its 2004 Section 311 rate case, the Company agreed to move from a system-wide fuel percentage to zonal fuel percentages. Accordingly, in all of the annual fuel filings made subsequent to the FERC’s acceptance of the 2004 rate case settlement, the Company has filed for fixed fuel percentages for the East Zone and the West Zone, respectively. On November 15, 2007, Enogex made its annual filing to establish the fixed fuel percentages for its East Zone and West Zone for calendar year 2008 (“2008 Fuel Year”). There were no protests and the FERC accepted the proposed zonal fuel percentages for 2008 Fuel Year by order of December 19, 2007.

Market-Based Rate Authority

On December 22, 2003, OG&E and OERI filed a triennial market power update based on the supply margin assessment test. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address the new interim tests. OG&E and OERI submitted a compliance filing to the FERC on February 7, 2005 that applied the interim tests to OG&E and OERI. In the compliance filing, OG&E and OERI passed the pivotal supplier screen but did not pass the market share screen in OG&E’s control area. OG&E and OERI provided an explanation as to why their failure of the market share screen in OG&E’s control area should not be viewed as an indication that they can exercise generation market power.

On June 7, 2005, the FERC issued an order on OG&E’s and OERI’s market-based rate filing. Because OG&E and OERI failed the market share screen for OG&E’s control area, the FERC established hearing procedures to investigate whether OG&E and OERI may continue to sell power at market-based rates in OG&E’s control area. The order established a rebuttable presumption that OG&E and OERI have the ability to exercise market power in OG&E’s control area. OG&E and OERI were requested to provide additional information that demonstrates to the FERC that they cannot exercise market power in the first-tier markets as well. However, the order conditionally allows OG&E and OERI to sell power in first-tier markets subject to OG&E and OERI providing additional information that clearly shows that they pass the market share screen for the first-tier markets. OG&E and OERI provided that additional information on July 7, 2005. On August 8, 2005, OG&E and OERI informed the FERC that they will: (i) adopt the FERC default rate mechanism for sales of one week or less to loads that sink in OG&E’s control area; and (ii) commit not to enter into any sales with a duration of between one week and one year to loads that sink in OG&E’s control area. OG&E and OERI also informed the FERC that any new agreements for long-term sales (one year or longer in duration) to loads that sink in OG&E’s control area will be filed with the FERC and that OG&E and OERI will not make such sales under their respective market-based rate tariffs. On January 20, 2006, the FERC issued a Notice of Institution of Proceeding and Refund Effective Date for the purpose of establishing the date from which any subsequent market-based sales would be subject to refund in the event the FERC concludes after investigation that the rates for such sales are not just and reasonable. The refund effective date was March 27, 2006.

On March 21, 2006, the FERC issued an order conditionally accepting OG&E’s and OERI’s proposal to mitigate the presumption of market power in OG&E’s control area. First, the FERC accepted the additional information related to first-tier markets submitted by OG&E and OERI, and concluded that OG&E and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company to make certain revisions

to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within OG&E’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within OG&E’s control area (instead of only to sales sinking to load within OG&E’s control area). On April 20, 2006, the Company submitted: (i) a compliance filing containing the specified revisions to the Company’s market-based rate tariffs and the new cost-based rate tariff; and (ii) a request for rehearing asking the FERC to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the FERC issued a tolling order that effectively provided the FERC additional time to consider the April 20, 2006 rehearing request. On July 25, 2006 and August 25, 2006, pursuant to a FERC March 20, 2006 order, OG&E and OERI filed revisions to their market-based rate tariffs to allow them to sell energy imbalance service into the wholesale markets administered by the SPP at market-based rates. The FERC has not yet acted on OG&E’s April 20, 2006, July 25, 2006 or August 25, 2006 filings. On February 6, 2007, OG&E and OERI submitted to the FERC a change in status report notifying the FERC that OG&E has placed into service OG&E’s Centennial wind farm, a wind farm with a nameplate capacity rating of 120 MW. OG&E and OERI explained that adding this capacity was not material to the FERC’s grant of market-based rate status to OG&E and OERI. On March 9, 2007, the FERC accepted OG&E’s and OERI’s change of status filing. On June 21, 2007, the FERC issued a final rule codifying and revising standards for market-based rate sales of electric energy, capacity and ancillary services. This final rule clarifies the scope of the mitigation applicable to sales within OG&E’s control area. OG&E began complying with the final rule and must formally incorporate certain provisions into its market-based rate tariff the next time OG&E proposes a tariff change, makes a change in status filing or submits an updated market power analysis.

North American Electric Reliability Council

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC approved the North American Electric Reliability Council (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. On April 19, 2007, the FERC approved the SPP as a Regional Entity whose primary function is to review and enforce compliance of reliability standards with all registered entities in the region. In March 2007, the FERC approved mandatory NERC reliability standards which became effective June 18, 2007. In June 2007, OG&E completed a NERC readiness evaluation. OG&E received the evaluation report from the NERC in December 2007 and has already implemented several of the recommendations. The Company is subject to a NERC readiness evaluation and compliance audit every three years. The next compliance audit is scheduled for 2008 and the next readiness evaluation is scheduled for 2010.

National Legislative Initiatives

In December 2007, the United States Congress passed and the President signed into law the Energy Independence and Security Act of 2007. Among other things, that legislation aims to create significant changes in the use of energy in the United States in the transportation and electric utility sectors. With regard to the impact on the utility sector in general and the Company in particular, the new energy law has a large number of provisions designed to increase the efficiency with which electricity is used in homes, as well as in commercial and industrial applications. New federal electric efficiency standards are to be developed and imposed on a wide range of appliances and equipment, buildings and manufacturing facilities. In addition, beyond direct action mandated to be taken by federal agencies to incentivize increased use of combined heat and power systems, cogeneration and demand response programs, the legislation also directs state public utility commissions to consider imposing similar proposals on utilities operating within the states’ retail jurisdiction. Collectively, these provisions of the new law are intended to lower demand growth in the electricity sector through efficiency gains and reduce air emissions associated with the generation of electricity by utilities and the use of electricity by virtually every customer segment in the economy.

In December 2007, the United States Senate Environmental and Public Works Committee reported a bill to impose a federal “cap and trade” regime to control greenhouse gas emissions in this country. The legislation would impose significant regulatory and cost burdens on the utility sector, especially for those utilities like OG&E with coal-based generation. The Senate leadership intends to present the bill in 2008. In the United States House of Representatives, the Democratic leadership also aspires to have a global climate bill in 2008, with the intent to reach a final bill with the Senate that can be presented to the President before the end of 2008.

State Legislative Initiatives

In the 2007 legislative session, legislation was introduced in the Oklahoma legislature which proposed that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. Historically, the Company has used the LIFO method of accounting for inventory removed from storage or stockpiles. This legislation passed the legislature and was signed into law on June 5, 2007 and was effective January 1, 2008. OG&E filed an application with the OCC in September 2007 to address the accounting issues for the change in accounting for fuel inventory. In December 2007, the OCC issued an order approving the change in accounting for fuel inventory effective

January 1, 2008. This change in accounting for fuel inventory is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

Legislation was enacted in Oklahoma in the 1990’s that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation was delayed and seems unlikely to proceed anytime in the near future. Yet, if ultimately enacted, this legislation could deregulate OG&E’s electric generation assets and cause OG&E to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect OG&E’s electric transmission and distribution assets and OG&E believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

Summary

The Energy Policy Act of 2005, the actions of the FERC, the restructuring legislation in Oklahoma and other factors are intended to increase competition in the electric industry. OG&E has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While OG&E is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and OG&E is advocating this position vigorously.

18.

Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, as of December 31:

	2007		2006
	Carrying	Fair	Carrying	Fair
December 31(In millions)	Amount	Value	Amount	Value

Price Risk Management Assets
Energy Trading Contracts	$ 8.0	$ 8.0	$ 39.1	$ 39.1
Interest Rate Swaps	---	---	0.9	0.9

Price Risk Management Liabilities
Energy Trading Contracts	$ 30.2	$ 30.2	$ 6.7	$ 6.7
Interest Rate Swaps	1.7	1.7	---	---

Long-Term Debt
Senior Notes	$ 807.4	$ 825.3	$ 807.2	$ 820.7
Industrial Authority Bonds	135.4	135.4	135.4	135.4
Enogex Notes – continuing operations	402.8	436.8	406.7	433.5

The carrying value of the financial instruments on the Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swaps and energy trading contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. 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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

OGE Energy Corp.

We have audited the accompanying consolidated balance sheets and statements of capitalization of OGE Energy Corp. as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of OGE Energy Corp. at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), OGE Energy Corp.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2008 expressed an unqualified opinion thereon.

As discussed in Notes 1, 4, 6, 9 and 14 to the consolidated financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 123 (Revised), “Share-Based Payment,” and Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and in 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” and Financial Accounting Standards Board Interpretation No. 39 (As Amended), “Offsetting of Amounts Related to Certain Contracts.”

/s/ Ernst & Young LLP

Ernst & Young LLP

Oklahoma City, Oklahoma

February 26, 2008

Supplementary Data

Interim Consolidated Financial Information (Unaudited)

In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present the Company’s consolidated results of operations for such periods:

Quarter ended (In millions, except per share data)		Mar 31		Jun 30		Sep 30		Dec 31		Total

Operating revenues	2007	$	881.5	$	913.4	$	1,044.5	$	958.2	$	3,797.6
	2006		1,109.8		934.3		1,130.6		830.9		4,005.6

Operating income	2007	$	46.2	$	117.2	$	218.3	$	73.6	$	455.3
	2006		51.8		117.7		220.6		42.6		432.7

Net income	2007	$	17.2	$	62.6	$	126.8	$	37.6	$	244.2
	2006		24.9		93.7		121.4		22.1		262.1

Basic earnings per average common share	2007	$	0.19	$	0.68	$	1.38	$	0.41	$	2.66
	2006		0.27		1.03		1.33		0.25		2.88

Diluted earnings per average common share	2007	$	0.19	$	0.68	$	1.37	$	0.40	$	2.64
	2006		0.27		1.02		1.31		0.24		2.84

In January 2007, OG&E determined that the approved tariffs in its December 12, 2005 OCC rate case order had inadvertently authorized OG&E to collect, and OG&E had collected, approximately $26.7 million of additional fuel-related revenues during 2006 that was not intended by the order. As a result, OG&E filed with the OCC in January 2007 amendments to its previously-authorized tariffs in order to cease recovery of the fuel-related revenues not intended by the December 12, 2005 order. OG&E recorded a reduction in operating revenues of approximately $26.7 million and an increase in interest expense of approximately $0.5 million, which resulted in an after tax reduction in net income of approximately $16.7 million in the fourth quarter of 2006. On a quarterly basis, collections of such additional amounts under the previously-authorized tariffs represented approximately $7.8 million of operating revenues ($4.8 million of net income) for the quarter ended March 31, 2006, approximately $7.7 million of operating revenues ($4.7 million of net income) for the quarter ended June 30, 2006 and approximately $5.9 million of operating revenues ($3.6 million of net income) for the quarter ended September 30, 2006.

Dividends

COMMON STOCK

•

Common quarterly dividends paid (as declared) in 2007 were $0.34 each for the first three quarters of 2007 and was $0.3475 for the fourth quarter of 2007. Common quarterly dividends paid (as declared) in 2006 were $0.33 ¼ each for the first three quarters of 2006 and was $0.34 for the fourth quarter of 2006. Common quarterly dividends paid (as declared) in 2005 were $0.33 ¼.

•	Present rate – $0.34 ¾

•	Payable 30th of January, April, July, and October

Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (“CEO”) and chief financial officer (“CFO”), allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company’s management, including the CEO and CFO, of the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

Management’s Report on Internal Control Over Financial Reporting

The management of OGE Energy Corp. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe that, as of December 31, 2007, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent auditors have issued an attestation report on the Company’s internal control over financial reporting. This report appears on the following page.

/s/ Peter B. Delaney		/s/ Danny P. Harris
Peter B. Delaney, Chairman of the Board, President		Danny P. Harris, Senior Vice President
and Chief Executive Officer		and Chief Operating Officer

/s/ James R. Hatfield		/s/ Scott Forbes
James R. Hatfield, Senior Vice President		Scott Forbes, Controller and
and Chief Financial Officer		Chief Accounting Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

OGE Energy Corp.

We have audited OGE Energy Corp.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). OGE Energy Corp.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on our assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, OGE Energy Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and statements of capitalization of OGE Energy Corp. as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 of OGE Energy Corp. and our report dated February 26, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Ernst & Young LLP

Oklahoma City, Oklahoma

February 26, 2008

P.O. Box 321

Oklahoma City, Oklahoma

73101-0321

(405) 553-3000

PLEASE DATE AND SIGN EXACTLY AS NAME APPEARS BELOW. EACH JOINT OWNER SHOULD SIGN. ATTORNEY, EXECUTOR,

ADMINISTRATOR, TRUSTEE OR OTHERS SIGNING IN A REPRESENTATIVE CAPACITY SHOULD GIVE THEIR FULL TITLES.

Please mark
your votes as
indicated in
this example

The Board recommends a vote FOR the election as directors of the nominees named below, FOR ratification of the appointment of Ernst & Young LLP as
the Company’s principal independent accountants, FOR approval of the OGE Energy Corp. 2008 Stock Incentive Plan, FOR approval of the OGE Energy
Corp. 2008 Annual Incentive Compensation Plan and AGAINST the shareowner proposal to eliminate the classification of the terms of the directors.

1. Election of Directors

FOR all
NOMINEES (list
exceptions below)

WITHHOLD
AUTHORITY
to vote for all nominees

2. Ratify the appointment of Ernst & Young LLP as our principal FOR AGAINST ABSTAIN

independent accountants.

NOMINEES:
01 Kirk Humphreys
02 Linda Petree Lambert
03 Leroy Richie

3. Approval of the OGE Energy Corp. 2008 Stock Incentive Plan. FOR AGAINST ABSTAIN

Instructions: To withhold authority to vote for any individual
nominee, write that nominee’s name on the line above.

4. Approval of the OGE Energy Corp. 2008 Annual Incentive FOR AGAINST ABSTAIN

Compensation Plan.

5. Shareowner proposal to eliminate the classification of the terms FOR AGAINST ABSTAIN

of the directors.

6. In their discretion, the proxies are authorized to vote upon such other

business as may properly come before the meeting.

Discontinue mailing of I will attend the

duplicate Annual Report Annual Meeting.

X / / 2008

Signature of Shareowner Date

FOLD AND DETACH HERE

WE ENCOURAGE YOU TO TAKE ADVANTAGE OF INTERNET OR TELEPHONE VOTING,

BOTH ARE AVAILABLE 24 HOURS A DAY, 7 DAYS A WEEK.

Internet and telephone voting is available through 11:59 PM Eastern Time

the day prior to annual meeting day.

Your Internet or telephone vote authorizes the named proxies to vote your shares in the same manner

as if you marked, signed and returned your proxy card.

INTERNET http://www.proxyvoting.com/oge		TELEPHONE 1-866-540-5760		MAIL
Use the Internet to vote your proxy.	OR	Use any touch-tone telephone to	OR	Mark, sign and date your proxy card
Have your proxy card in hand when		vote your proxy. Have your proxy		and return it in the
you access the web site.		card in hand when you call.		enclosed postage-paid envelope.

If you vote your proxy by Internet or by telephone, you do NOT need to mail back your proxy card.

To vote by mail, mark, sign and date your proxy card and return it in the enclosed postage-paid envelope.

Choose MLink^SM for fast, easy and secure 24/7 online access to your future proxy materials, investment plan statements, tax documents and more. Simply log on to Investor ServiceDirect® at www.bnymellon.com/shareowner/isd where step-by-step instructions will prompt you through enrollment.

You can view the Annual Report and Proxy Statement

on the Internet at http://bnymellon.mobular.net/bnymellon/oge

OGE ENERGY CORP.
Annual Meeting of Shareowners
May 22, 2008

The undersigned hereby appoints Peter B. Delaney, Luke R. Corbett and Robert Kelley, and each of them severally, with full power of substitution and with full power to act with or without the other, as the proxies of the undersigned to represent and to vote all shares of stock of OGE Energy Corp. held of record by the undersigned on March 24, 2008, at the Company’s Annual Meeting of Shareowners to be held on May 22, 2008, and at all adjournments thereof, on all matters coming before said meeting.

THIS PROXY, WHICH IS SOLICITED BY THE BOARD OF DIRECTORS, WILL BE VOTED AS DIRECTED. IF NO DIRECTION IS MADE, THIS PROXY WILL BE VOTED FOR THE ELECTION AS DIRECTORS OF THE NOMINEES NAMED ON THE REVERSE SIDE OF THIS PROXY CARD, FOR THE RATIFICATION OF THE APPOINTMENT OF ERNST & YOUNG LLP AS THE COMPANY’S PRINCIPAL INDEPENDENT ACCOUNTANTS, FOR APPROVAL OF THE OGE ENERGY CORP. 2008 STOCK INCENTIVE PLAN, FOR APPROVAL OF THE OGE ENERGY CORP. 2008 ANNUAL INCENTIVE COMPENSATION PLAN AND AGAINST THE SHAREOWNER PROPOSAL TO ELIMINATE THE CLASSIFICATION OF THE TERMS OF THE DIRECTORS.

PLEASE VOTE BY INTERNET, TELEPHONE, OR MARK, DATE, SIGN AND RETURN THIS PROXY CARD PROMPTLY USING THE ENCLOSED ENVELOPE. Unless you attend and vote in person, you MUST vote by Internet, telephone, or sign and return your proxy in order to have your shares voted at the meeting.

(Continued on reverse side)

FOLD AND DETACH HERE

321 North Harvey Avenue

Oklahoma City, Oklahoma 73102

RETAIN FOR ADMITTANCE

Annual Meeting of

OGE Energy Corp. Shareowners

Thursday, May 22, 2008 10:00 a.m.

National Cowboy and Western Heritage Museum

1700 Northeast 63rd Street

Oklahoma City, Oklahoma

LOCATION OF THE NATIONAL COWBOY AND WESTERN HERITAGE MUSEUM

East Bound or West Bound 1-44

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.

It is important that your shares are represented at this meeting, wether or not you attend the meeting in person. To make sure your shares are represented, we urge you to vote by Internet, telephone, or complete and mail the proxy card above.

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:

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