	UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
		Washington, D.C. 20549

FORM 10-K

(Mark One)

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

	THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2005

OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)

Oklahoma		73-1481638
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (405) 553-3000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock		New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase Series A Preferred Stock		New York Stock Exchange and Pacific Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes No X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer X Accelerated Filer Non-Accelerated Filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No X

As of June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $2,605,521,218 based on the number of shares held by non-affiliates (90,031,832) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $28.94.

As of January 31, 2006, 90,570,241 shares of common stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company’s 2006 annual meeting of stockholders is incorporated by reference into Part III of this Form 10-K.

OGE ENERGY CORP.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2005

TABLE OF CONTENTS

Part I	Page
Item 1. Business	1
The Company	1
Electric Operations – OG&E	2
General	2
Regulation and Rates	4
Rate Activities and Proposals	6
Fuel Supply	7
Natural Gas Pipeline Operations – Enogex	8
Finance and Construction	15
Environmental Matters	16
Employees	16
Access to Securities and Exchange Commission Filings	16

Item 1A. Risk Factors	16

Item 1B. Unresolved Staff Comments	21

Item 2. Properties	22

Item 3. Legal Proceedings	23

Item 4. Submission of Matters to a Vote of Security Holders	26
Executive Officers of the Registrant	27

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities	29

Item 6. Selected Financial Data	31

Item 7. Management’s Discussion and Analysis of Financial Condition and Results Operations	32

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	60

Item 8. Financial Statements and Supplementary Data	65

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	118

Item 9A. Controls and Procedures	118

Item 9B. Other Information	121

Part III
Item 10. Directors and Executive Officers of the Registrant	121

Item 11. Executive Compensation	121

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters	123

Item 13. Certain Relationships and Related Transactions	123

Item 14. Principal Accounting Fees and Services	123

Part IV
Item 15. Exhibits, Financial Statement Schedules	124

Signature	131

PART I

Item 1. Business.

THE COMPANY

OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments. For financial information regarding these segments, see Note 13 of Notes to Consolidated Financial Statements.

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, 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.

OG&E has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail in Note 15 of Notes to Consolidated Financial Statements.

The operations of the Natural Gas Pipeline segment are conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consist of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing of natural gas. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture margins across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Prior to October 31, 2005, Enogex owned, through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), a controlling interest in and operated Ozark Gas Transmission, L.L.C. (“OGT”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. On October 31, 2005, Enogex sold its interest in Enogex Arkansas Pipeline Corporation (“EAPC”), which held the NOARK interest. Also, during the third quarter of 2005, Enogex Compression Company, LLC (“Enogex Compression”) sold it majority interest in Enerven Compression Services, LLC (“Enerven”), a joint venture focused on the rental of natural gas compression assets. The EAPC and Enerven businesses have been reported as discontinued operations in the Company’s Consolidated Financial Statements and are discussed further in Note 4 of Notes to Consolidated Financial Statements.

The Company was incorporated in August 1995 in the state of Oklahoma and its principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.

Company Strategy

The Company’s vision is to be a regional energy company focused on its regulated utility business and natural gas pipeline business that is recognized for operational excellence and financial performance. As explained below, the Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth and maintenance of strong credit ratings.

OG&E has been focused on its Customer Savings and Reliability Plan, which provides for increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment and deploy newer technology that improves operational and environmental performance. As part of this plan, 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. Capacity payment savings from reduced cogeneration payments and fuel savings from the McClain Plant will be utilized to help mitigate the price increases associated with these investments. In 2005 OG&E filed a rate case to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. An order was issued by the OCC on December 12, 2005 providing for a rate increase of approximately $42.3 million and OG&E implemented the new electric rates in

January 2006. For additional information regarding the McClain Plant acquisition, the new electric rates and related regulatory matters, see Note 15 of Notes to Consolidated Financial Statements.

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Enogex’s marketing business, which concentrates principally on origination of physical sales of natural gas, has expanded into the Gulf Coast and Rocky Mountain markets. Also, in 2005, Enogex’s marketing business implemented a refocused strategy that seeks to minimize the amount of capital employed and to complement better the natural gas pipeline business. Enogex’s improved financial performance and increased flexibility from the reduction of its long-term debt has enabled Enogex to begin to contribute to funding the Company’s dividend. As discussed above, during 2005, Enogex sold its interests in EAPC and Enerven and will continue to review its asset portfolio and seek to divest underperforming or non-strategic assets.

The Company’s business strategy is to continue maintaining the diversified asset position of OG&E and Enogex so as to provide competitive energy products and services to customers primarily in the south central United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as a vertically integrated utility engaged in the generation, transmission and distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s consolidated assets will be in Enogex’s businesses. At December 31, 2005, OG&E and Enogex represented approximately 66 percent and 32 percent, respectively, of the Company’s consolidated assets. The remaining two percent of the Company’s consolidated assets were primarily at the holding company. In addition to the incremental growth opportunities that Enogex provides, the Company believes that many of the risk management practices, commercial skills and market information available from Enogex provide value to all of the Company’s businesses subject to the evolving federal regulations of the FERC in regard to the operations of the wholesale power market. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview” for a further discussion.

ELECTRIC OPERATIONS - OG&E

General

The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. During 2005, five other communities and four rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 2.0 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 269 communities that OG&E serves, 243 are located in Oklahoma and 26 in Arkansas. OG&E derived approximately 88 percent of its total electric operating revenues for the year ended December 31, 2005 from sales in Oklahoma and the remainder from sales in Arkansas.

OG&E’s system control area peak demand as reported by the system dispatcher during 2005 was approximately 6,145 MW’s on July 22, 2005. OG&E’s load responsibility peak demand was approximately 5,766 MW’s on July 22, 2005, resulting in a capacity margin of approximately 15.8 percent. As reflected in the table below and in the operating statistics on page 3, there were approximately 26.1 million megawatt-hour (“MWH”) sales in 2005 as compared to approximately 24.8 million in 2004 and 25.1 million in 2003. MWH sales to OG&E’s customers (“system sales”) increased approximately 5.3 percent in 2005 primarily due to warmer weather during 2005. Sales to other utilities and power marketers (“off-system sales”) remained flat in 2005. Variances in off-system sales are due in large part to the changing supply and demand needs on OG&E’s generation system and the market for off-system sales.

Variations in MWH sales for the three years are reflected in the following table:

			Increase/		Increase/		Increase/
	2005		(Decrease)	2004	(Decrease)	2003	(Decrease)

System Sales (A)		26.0	5.3%	24.7	(0.1)%	25.0	1.6%
Off-System Sales (A)		0.1	---%	0.1	---%	0.1	(67.0)%
Total Sales		26.1	5.3%	24.8	(0.1)%	25.1	0.8%

(A)	Sales are in millions of MWH’s.

OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity. OG&E is currently in negotiations regarding the renewal of its Oklahoma City franchise and OG&E currently expects the franchise to be renewed for a 25-year term later this year.

Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. See Note 15 of Notes to Consolidated Financial Statements for a discussion of the potential impact on competition from federal and state legislation.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS

Year ended December 31 (In millions)		2005			2004			2003

ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)		24.8			22.6			22.5
Purchased		3.3			4.2			4.5
Total generated and purchased		28.1			26.8			27.0
Company use, free service and losses		(2.0)		(2.0)			(1.9)
Electric energy sold		26.1			24.8			25.1

ELECTRIC ENERGY SOLD (Millions of MWH)
Residential		8.5			7.9			8.2
Commercial		6.0			5.7			5.8
Industrial		7.2			7.0			6.8
Public authorities		2.8			2.7			2.7
Sales for resale		1.5			1.4			1.5
System sales		26.0			24.7			25.0
Off-system sales		0.1			0.1			0.1
Total sales		26.1			24.8			25.1

ELECTRIC OPERATING REVENUES (In millions)
Residential	$	663.6	$		611.4	$		601.4
Commercial		418.9			389.9			372.5
Industrial		355.6			326.7			293.4
Public authorities		173.1			158.5			146.1
Sales for resale		67.7			57.0			57.7
Provision for refund on gas transportation and storage case		(2.0)			(6.9)			---
System sales revenues		1,676.9			1,536.6			1,471.1
Off-system sales revenues		4.9			0.8			4.1
Other		38.9			40.7			41.9
Total Electric Operating Revenues	$	1,720.7	$		1,578.1	$		1,517.1

ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential		639,733			630,736			622,527
Commercial		81,728			80,786			80,265
Industrial		9,472			9,420			8,970
Public authorities		14,515			14,022			13,658
Sales for resale		45			44			50
Total		745,493			735,008			725,470

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,043.60	$		975.08	$		970.04
Average annual use (kilowatt-hour (“KWH”))		13,445			12,630			13,202
Average price per KWH (cents)	$	7.76	$		7.72	$		7.35

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, 2005 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 jurisdictional rates.

Regulatory Matters

Gas Transportation and Storage Agreement

As part of the settlement of an OG&E rate case in November 2002 (the “Settlement Agreement”), OG&E agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the Settlement Agreement. Because the required integrated service was not available in the marketplace from parties other than Enogex, OG&E advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of OG&E’s natural gas-fired generation facilities. OG&E will pay Enogex annual demand fees of approximately $46.8 million for the right to transport specified maximum daily quantities (“MDQ”) and maximum hourly quantities (“MHQ”) of gas at various minimum gas delivery pressures depending on the operational needs of the individual generating facility. In addition, OG&E supplies system fuel in-kind for its pro-rata share of actual fuel and lost and unaccounted for gas on the transportation system. To the extent OG&E transports gas in quantities in excess of the prescribed MDQ’s or MHQ’s, it pays an overrun service charge. During the years ended December 31, 2005, 2004 and 2003, OG&E paid Enogex approximately $47.6 million, $49.6 million and $44.7 million, respectively, for gas transportation and storage services.

On July 14, 2005, the OCC issued an order in this case approving a $41.9 million annual recovery. The OCC order disallowed the recovery by OG&E of the amount that Enogex charges OG&E for the cost of fuel used, or otherwise unaccounted for, in providing natural gas transportation and storage service to OG&E. Over the last three years, this amount has ranged from $1.2 million to $3.7 million annually. This amount was approximately $1.2 million in 2005 and is projected to be approximately $0.5 million in 2006. The OCC’s order required OG&E to refund to its Oklahoma customers the difference between the amounts collected from such customers in the past based on an annual rate of $46.8 million for gas transportation and storage services and the $41.9 million annual rate authorized by the OCC’s order. Based on the order, OG&E’s refund obligation was approximately $8.8 million. OG&E began refunding this obligation in September 2005 through its automatic fuel adjustment clause. The balance of the refund obligation was approximately $6.0 million at December 31, 2005. For further information, see Note 15 of Notes to Consolidated Financial Statements.

In connection with the Enogex gas transportation and storage agreement, OG&E has also recorded a refund obligation in Arkansas. OG&E expects to meet with the APSC in early 2006 to determine the amount of the refund. OG&E estimated its refund obligation to be approximately $1.1 million at December 31, 2005 to Arkansas customers assuming the Arkansas refund obligation is calculated consistent with the Oklahoma calculation.

OG&E Oklahoma Rate Case Filing

On May 20, 2005, OG&E filed with the OCC an application for an annual rate increase of approximately $89.1 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. As a result of the McClain Plant acquisition completed on July 9, 2004, and consistent with the 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. OG&E’s rate case application included an estimate of $25.9 million related to the McClain Plant regulatory asset. At December 31, 2005, the actual incurred expenses included in the McClain Plant regulatory asset were approximately $24.9 million. Such costs will be recovered over a four-year time period as authorized in the OCC rate order beginning in January 2006. The OCC also authorized approximately $15.5 million of the $24.9 million regulatory asset to be included in OG&E’s rate base for purposes of earning a return. The application also included, among other things, implementation of enhanced reliability programs in OG&E’s system, increased fuel oil inventory, the establishment of a separate recovery mechanism for major storm expense, the establishment of new rate classes for public schools and related facilities, the establishment of a military base rider, the establishment of a new low income assistance tariff and the proposal to make the guaranteed flat bill pilot tariff permanent for residential and small business customers.

On September 12, 2005, several parties filed responsive testimony reflecting various positions on the issues related to this case. In particular, the testimony of the OCC Staff recommended that OG&E be entitled a rate increase of approximately $13.0 million, one-seventh the amount requested by OG&E in its May 20, 2005 application. The recommendations in the testimony of the Attorney General’s office and the Oklahoma Industrial Energy Consumers recommended a rate decrease of approximately $24 million and $31 million, respectively. Hearings in the rate case began on October 10, 2005 and concluded on October 24, 2005. On November 3, 2005, the Referee appointed by the OCC for this proceeding issued a report recommending an estimated rate increase of approximately $42 million for OG&E. On December 12, 2005, the OCC issued an order providing for a $42.3 million increase in rates and a 10.75 percent return on equity, based on a capital structure consisting of 55.7 percent equity and 44.3 percent debt. The new rates became effective in January 2006. Also included in the order, among other things, are new depreciation rates effective January 2006 and a provision which modified OG&E’s mechanism for the recovery of over or under recovered fuel costs from its customers to allow interest to be applied to the over or under recovery. See “Rate Activities and Proposals” for a discussion of other items included in the OCC order.

Southwest Power Pool

OG&E is a member of the Southwest Power Pool (“SPP”), the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. The regional state committee, which is comprised of commissioners of the applicable state regulatory commissions, finished its process of formulating a methodology for funding transmission expansion in the SPP control area by allocating costs of transmission expansion to the SPP members who benefit. The SPP Board of Directors adopted this plan and filed it with the FERC on February 28, 2005, Docket No. ER05-652. The FERC conditionally accepted the plan on April 21, 2005 with an effective date of May 5, 2005. The SPP made a second compliance filing on October 20, 2005 on various minor issues associated with the plan. On January 11, 2006, the FERC conditionally accepted the compliance filing, but required the SPP to make minor wording changes within 30 days. The SPP filed these minor wording changes on February 10, 2006.

Also, the SPP filed on June 15, 2005, Docket No. ER05-1118, to create a real-time, offer-based imbalance energy market which will require cash settlements for over or under generation. Market participants, including OG&E, will be required to submit resource plans and can submit offer curves for each resource available for dispatch. In addition, the filing contains provisions allowing the SPP to order certain dispatching of generating units and a market monitoring plan which provides a clear set of rules, the potential consequences if the rules are violated and the areas in which an independent market monitor will examine and report. The scheduled implementation date of the imbalance energy market is May 1, 2006. See Note 15 of Notes to Consolidated Financial Statements for a further discussion.

Regulatory Assets and Liabilities

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.

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.

At December 31, 2005 and 2004, OG&E had regulatory assets of approximately $189.2 million and $137.3 million, respectively, and regulatory liabilities of approximately $118.1 million and $122.2 million, respectively.

As discussed in Note 15 of Notes to Consolidated Financial Statements, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. The Arkansas legislation was repealed and implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented, 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 and Arkansas 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.

See Note 15 of Notes to Consolidated Financial Statements for a discussion of certain regulatory matters including the gas transportation and storage contract between OG&E and Enogex, OG&E’s 2005 rate case order, security enhancements, national energy legislation and state legislative initiatives.

Rate Activities and Proposals

Since 2002, OG&E has had several different customer programs and rate options. The Guaranteed Flat Bill (“GFB”) option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set price for an entire year. Budget-minded customers that desire a fixed monthly bill may benefit from the GFB option. The GFB option received OCC approval for permanent rate status in OG&E’s recently concluded rate case. A second tariff rate option provides a “renewable energy” resource to OG&E’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and is available as a voluntary option to all of OG&E’s Oklahoma retail customers. Oklahoma’s availability of wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers. A third rate offering available to commercial and industrial customers is levelized demand billing. This program is beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. Another program being offered to OG&E’s commercial and industrial customers is a voluntary load curtailment program. This program provides customers with the opportunity to curtail on a voluntary basis when OG&E’s system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.

The previously discussed rate options coupled with OG&E’s other rate choices provide many tariff options for OG&E’s Oklahoma retail customers. OG&E’s rate choice flexibility, reduction in cogeneration rates, acquisition of additional generation resources and overall low costs of production and deliverability are expected to provide valuable benefits for our customers for many years to come. The revenue impacts associated with these options are indeterminate in future years since customers may choose to remain on existing rate options instead of volunteering for the new rate option choices. There was no overall material impact in 2004 or 2005 associated with these rate options, but minimal revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose these programs. In 2005, the GFB pilot customers continued to renew at the 2004 renewal rate of over 90 percent.

As part of the rate order issued by the OCC in December 2005, OG&E received OCC approval for the creation of two new rate classes, Public Schools-Demand and Public Schools Non-Demand. These two classes of service will provide OG&E flexibility to provide targeted programs for load management to public schools and their unique usage patterns. Another item approved in the order was the creation of service level fuel differentiation which allows customers to pay fuel costs that better reflect energy losses on a service level basis. The OCC order also approved a military base rider which demonstrates Oklahoma’s continued commitment to our military partners. OG&E’s highly successful wind program was authorized to lower its cost on a per kwh basis, which provides subscribing customers the increased incentive to hedge against future natural gas prices. The order also enables OG&E’s low-income qualified customers to receive relief on their summer electric bills by waiving the customer charge on their monthly bills from June to September of each year. Also included in OG&E’s rate case application, but not approved, was the establishment of a separate recovery mechanism for major storm expense.

Fuel Supply

During 2005, approximately 70 percent of the OG&E-generated energy was produced by coal-fired units and 30 percent by natural gas-fired units. Of OG&E’s 6,122 total MW capability reflected in the table under Item 2. Properties, approximately 3,553 MW’s, or 58 percent, are from natural gas generation and approximately 2,569 MW’s, or 42 percent, are from coal generation. Though OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. A slight decline in the percentage of coal generation in future years is expected to result from increased usage of natural gas generation required to meet growing energy needs. Over the last five years, the weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

	2005	2004	2003	2002	2001
Coal	$ 0.98	$ 1.00	$ 0.93	$ 0.93	$ 0.81
Natural Gas	$ 8.76	$ 6.57	$ 6.46	$ 3.78	$ 4.91
Weighted Average	$ 3.21	$ 2.69	$ 2.27	$ 1.77	$ 1.97

The increase in the weighted average cost of fuel in 2005 and in 2004 was primarily due to increased natural gas prices and increased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2003 as compared to 2002 was primarily due to increased natural gas prices in 2003 partially offset by a lower amount of natural gas burned in 2003. The decrease in the weighted average cost of fuel in 2002 as compared to 2001 was primarily due to lower natural gas prices in 2002 partially offset by a higher amount of natural gas burned in 2002. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of these fuel costs that is not included in the base rates is recoverable through OG&E’s regulatorily approved automatic fuel adjustment clauses. See Note 1 of Notes to Consolidated Financial Statements.

Coal

All of OG&E’s coal-fired units, with an aggregate capability of approximately 2,569 MW’s, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts expiring in years 2010 and 2011. During 2005, OG&E purchased approximately 9.2 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Arch Coal Inc./Triton Coal Company, Peabody Coal Sales Company and Foundation Coal West, Inc. The combination of all coal has a weighted average sulfur content of less than 0.23 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.2 lbs. of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E’s coal units have an approximate emission rate of 0.49 lbs. of sulfur dioxide per MMBtu, well within the limitations of the provisions of the Federal Clean Air Act discussed in Note 15 of Notes to Consolidated Financial Statements.

OG&E has continued its efforts to maximize the utilization of its coal-fired units at its Sooner and Muskogee generating plants. See “Environmental Laws and Regulations” in Note 14 of Notes to Consolidated Financial Statements for a discussion of environmental matters affecting OG&E.

Coal Shipment Disruption

In July 2005, OG&E received notification from Union Pacific Railroad (“Union Pacific”) that, in May 2005, Union Pacific and BNSF Railway (“BNSF”) experienced successive derailments on the jointly-owned rail line serving the Southern Powder River Basin coal producers. According to Union Pacific, these two derailments were caused by track that had become unstable from an accumulation of coal dust in the roadbed combined with unusually heavy rainfall. BNSF, which maintains and operates the line, concluded that a significant part of the line needed to be repaired before normal train operations could resume. While the repairs were taking place, Union Pacific was unable to operate at full capacity from the Powder River Basin. In November 2005, Union Pacific notified OG&E that the South Powder River Basin joint line force majeure condition that was declared in May 2005 had ended. On December 2, 2005, BNSF completed the enhanced joint line maintenance program which opened the way for a return to normal operating conditions. It is expected that as rail traffic improves, OG&E will be able to increase its level of coal inventories. At December 31, 2005, OG&E had slightly more than 20 days of coal supply for each of its coal-fired units at its Sooner and Muskogee generating plants.

Natural Gas

OG&E utilized a request for bid (“RFB”) to acquire approximately 30 percent of its projected annual natural gas requirements for 2006. All of these contracts are tied to various gas price market indices and most will expire in December

2006. Additional natural gas supply for the summer of 2006 will be secured through a new RFB issued in the first quarter of 2006. OG&E will meet additional natural gas requirements with monthly and daily purchases as required.

In 1993, OG&E began utilizing a natural gas storage facility that allowed OG&E to maximize the value of its generation assets, which storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with OG&E. At December 31, 2005, OG&E had approximately 2.7 million MMBtu’s in natural gas storage that it acquired for approximately $10.5 million.

Wind

During 2003, OG&E contracted with FPL Energy for 50 MW’s of electricity generated at a wind farm near Woodward, Oklahoma. After more than one year of marketing wind power to OG&E’s residential and business customers, almost 9,000 subscribed for all or part of their electricity usage. As of January 31, 2006, OG&E’s current wind program is fully subscribed. Since OG&E last requested bids to determine the cost of adding wind to its system, natural gas prices have continued to rise and federal renewable energy tax credits have been extended.

On December 22, 2005, the Company issued a press release announcing that OG&E had entered into a non-binding letter of intent to purchase a 120 MW wind farm planned for construction in northwestern Oklahoma. Invenergy Wind Development Oklahoma LLC (“Invenergy LLC”) would develop the new wind power-generation facility to be owned and operated by OG&E. The wind farm, north of Woodward in Harper County, is expected to cost approximately $195 million, including the cost of transmission interconnection facilities. A definitive Agreement To Engineer, Procure and Construct Wind Generation Energy System (“EPC Contract”) was reached on February 20, 2006, subject to various conditions. Those conditions include agreement by the parties as to certain exhibits to the EPC Contract, approval of the EPC Contract by the OG&E Board of Directors and approval of the EPC Contract by the Manager of Invenergy LLC, all of which have to be completed on or before March 13, 2006. In addition, 90 days subsequent to the occurrence of these events, OG&E or Invenergy LLC have the unilateral right to terminate the EPC Contract if certain additional events have not occurred, including the following: (i) OCC approval of the terms of the EPC Contract and of a recovery rider providing OG&E the opportunity to recover all costs associated with the wind facility, including transmission interconnection and transmission upgrade costs; (ii) completion by the SPP of all necessary transmission studies; (iii) Invenergy LLC’s acquisition of certain land agreements; (iv) Invenergy LLC’s execution of a contract acceptable to OG&E with a balance of work contractor; and (v) Invenergy LLC’s acquisition of certain permits. If all of these conditions are met, the new wind farm is expected to be constructed and producing power on or before December 31, 2006. OCC hearings are expected to occur in April 2006. See Note 15 of Notes to Consolidated Financial Statements for a further discussion.

NATURAL GAS PIPELINE OPERATIONS - ENOGEX

Overview

The operations of the Natural Gas Pipeline segment are conducted through Enogex and consist of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing of natural gas. Enogex’s focus is to utilize its gathering, processing, transportation and storage capacity to execute physical, financial and service transactions to capture margins across different commodities, locations or time periods. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Enogex and its subsidiaries operate approximately 8,300 miles of intrastate gas gathering and transportation pipelines. Prior to October 31, 2005, Enogex owned, through a 75 percent interest in NOARK, a controlling interest in and operated OGT, a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. On October 31, 2005, Enogex sold its interest in EAPC, which held the NOARK interest. Also, during the third quarter of 2005, Enogex Compression sold it majority interest in Enerven, a joint venture focused on the rental of natural gas compression assets. The EAPC and Enerven businesses have been reported as discontinued operations in the Company’s Consolidated Financial Statements and are discussed further in Note 4 of Notes to Consolidated Financial Statements.

Strategy

The transportation, storage and gathering assets of Enogex provide OG&E strategic access to natural gas supplies, and flexible and reliable delivery terms that are required to fuel OG&E’s natural gas-fired generation facilities. Natural gas generation peaking units require the ability to quickly change their status, to meet both the peak and off-peak demands of the retail load particularly when coal units have an unscheduled outage. The gathering assets access major wellhead supply

sources primarily located across Oklahoma, and the integrated transportation and storage assets provide the ability to regulate the receipt and delivery of natural gas to match the instantaneous needs of these generation units.

Natural gas-fired generation units contribute their highest value when they have the capability to provide “load following” service to the customer (i.e., the ability of the generation unit to regulate generation to respond to and meet the instantaneous changes in customer demand). While the physical characteristics of natural gas units are known to provide quick start-up and on-line functionality, and while their ability to efficiently provide varying levels of electric generation relative to other forms of generation is further acknowledged, their ultimate effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond in a short term fashion to meet the corresponding fluctuating operational fuel requirements. The combination of these assets is critical to a generator’s ability to provide reliable generation service at reasonable prices to the consumer.

Not only is Enogex providing service to OG&E, but Enogex’s same assets provide firm and interruptible services to a significant portion of the other natural gas-fired generation loads in Oklahoma. Enogex understands the needs of generators, and more importantly has the appropriately-sized pipelines, compression and integrated storage assets necessary to meet their requirements.

Through Enogex’s gathering and processing assets, Enogex aggregates gas supplies for its markets and also for those markets accessible via its numerous intrastate and interstate pipeline connections. It aggressively pursues new supplies from wells drilled by producers primarily in the Anadarko and Arkoma basins. Oklahoma ranks second in the nation in onshore natural gas production and ranks second in the nation as a natural gas exporting state. The system capacity, due to its large diameter gathering pipelines and its natural gas processing plants, is capable of adapting to the varying pressure and quality requirements of mid-continent production. Enogex is able to provide low-pressure service to extend the production life of older wells as well as meeting the high-pressure requirements of new exploration. Enogex, through its processing plants, is also able to remove natural gas liquids from the wellhead gas streams, which is necessary for such gas to meet quality specifications of the downstream marketplace.

Besides the core activities described above, the transportation capabilities and markets of Enogex’s pipeline assets provide other business opportunities. These include the ability of Enogex to use its pipeline system and storage assets as a “market hub”. At December 31, 2005, Enogex was connected to 14 other major pipelines at approximately 65 pipeline interconnect points providing access to markets in the western United States, the Midwest, Northeast, and Gulf Coast in addition to Oklahoma and adjoining states. As a result, Enogex’s assets sit in a key geographic region of the United States, with sufficient capacity to provide crosshaul transportation and storage services to a variety of utility and industrial customers that need to access mid-continent natural gas supply for their own needs, or to suppliers from other regions seeking to provide gas to on-system markets which Enogex serves.

Enogex’s marketing business provides products and services that support the market hub concept and are an important element in the Company realizing the full value of its transportation and storage assets. The marketing business offers the Company real-time and longer-term price discovery and valuation of energy commodities (natural gas and associated natural gas liquids) associated with the Company’s assets. The marketing business is instrumental in providing increased liquidity for these energy commodities, by focusing on developing supplies and markets that can access the Enogex systems either directly or via interconnections with intrastate and interstate pipelines. The marketing business also provides the Company the capability to provide risk management services to its customers.

The Company intends to continue to build upon the foundation of services and products that these assets can provide. In addition, the Company expects to generate additional margins by improving its ability to aggregate gas, maximize the operational capabilities of its assets and utilize commercial information available from the marketplace.

On November 4, 2005, Enogex announced that it had entered into a letter of intent with El Paso Corporation (“El Paso”) that is designed to accelerate El Paso’s Continental Connector Project. The letter of intent contemplates arrangements by which El Paso or an affiliate would execute an initial lease of up to 750,000 decatherms per day (“Dth/day”) of capacity on the Enogex pipeline system, with an option to expand up to 1.5 million Dth/day, so that the leased Enogex pipeline capacity would become an integral part of the Continental Connector Project. The letter of intent also contemplates a commitment by Enogex to secure up to 500,000 Dth/day of capacity subscriptions for the project. These arrangements would significantly reduce the amount of new mainline construction required for the project, resulting in less environmental disturbance and an earlier in-service target date of winter 2007-2008.

Under the letter of intent, the Continental Connector Project will use existing or expanded El Paso pipeline systems to transport capacity-constrained natural gas from Rocky Mountain and mid-continent supply regions to Custer, Oklahoma.

At Custer, this gas and local mid-continent production will be transported on existing and expanded Enogex systems for Continental Connector under a long-term lease arrangement for re-delivery in the vicinity of Bennington, Oklahoma. From there, gas will be transported on new El Paso pipeline facilities through the Perryville, Louisiana, Hub to a termination with Tennessee and Southern Natural Pipelines at Pugh, Mississippi.

Enogex intends to work with El Paso to determine whether to advance this project. However, the commitments and obligations under the letter of intent are subject to various conditions, including definitive documentation and boards of directors’ and regulatory approvals and there can be no assurance that the conditions will be satisfied. Pending satisfaction of these conditions, Enogex does not expect to incur material expenditures.

Dispositions

Beginning in 2002, Enogex evaluated, redesigned and reorganized its internal work processes and senior management structure in order to achieve cost reductions, revenue enhancements and strategic leadership within its businesses. As a part of this process, Enogex implemented a number of steps intended to maximize the value of its assets.

Processing and Compression Assets. During the fourth quarter of 2002, the Company recognized a pre-tax impairment loss of approximately $48.3 million in the Natural Gas Pipeline segment related to Enogex natural gas processing and compression assets. In the fourth quarter of 2003, the Company recognized a pre-tax impairment loss of approximately $9.2 million related to these natural gas compression assets.

During the year ended December 31, 2004, the Company sold certain of its compression and processing assets for approximately $5.0 million and recognized an after tax gain of approximately $1.8 million related to the sale of these assets. The carrying amount of the remaining assets (that were the subject of the impairment charges in the fourth quarters of 2002 and 2003) was approximately $2.6 million and $11.9 million at December 31, 2004 and 2003, respectively. As discussed below, for any remaining assets that were the subject of the impairment charges in the fourth quarters of 2002 and 2003, the Company either contributed the assets to the joint venture described below or reclassified these assets from held for sale to held and used as of December 31, 2004.

During the third quarter of 2004, Enogex entered into a joint venture arrangement with a third party and contributed certain of its natural gas compression assets (with a carrying amount of approximately $3.9 million) to the joint venture. The objective of the joint venture was to derive value from the assets by renting the natural gas compressors. Enogex Compression was created to act as the participating entity in the joint venture. Enogex Compression held a majority ownership in the joint venture, although the actual ownership percentages fluctuated based on the relative capital contributions of Enogex Compression and the third party member. The third party acted as the manager and conducted the daily operations of the joint venture. In April 2005, Enogex Compression received an unsolicited offer to buy its interest in Enerven. After evaluating this offer, Enogex Compression sold its interest in Enerven for approximately $7.3 million in August 2005. Enogex Compression recognized an after tax gain of approximately $1.8 million related to the sale of this business.

During the third quarter of 2004, the Company reclassified an asset from assets held for sale to assets held and used. This asset had a carrying amount of approximately $0.8 million at the time the asset was reclassified. In October 2004, the Company reclassified a large electric driven compressor that was previously classified as assets held for sale to assets held and used. This compressor had a carrying amount of approximately $1.2 million at September 30, 2004. In December 2004, the Company reclassified several compressors and processing plants that were previously classified as assets held for sale to assets held and used. These assets had a carrying amount of approximately $1.6 million at December 31, 2004.

Transportation and Storage. During September 2004, Enogex received notification from a customer that a transportation agreement involving four of Enogex’s non-contiguous pipeline asset segments located in West Texas and used to serve the customer’s power plants would be terminated effective December 31, 2004. In response to this notification, the Company recognized, during the third quarter of 2004, a pre-tax impairment loss of approximately $8.6 million in the Natural Gas Pipeline segment related to Enogex natural gas pipeline assets that were used to provide service to this customer. In December 2004, the Company received notification that all of this customers’ plants in West Texas were shut down and service was no longer required. The Company is currently evaluating other commercial opportunities for these assets as well as contacting other parties that may be interested in acquiring any of these assets.

In January 2003, OGT recognized a gain of approximately $5.3 million and approximately $1.1 million in minority interest expense related to the sale of approximately 29 miles of transmission lines of its pipeline.

Enogex regularly evaluates the long term stability, profitability and core competency of each of its businesses within the regulatory and market framework in which each business operates. Based on these evaluations, in September 2005, Enogex announced that it had entered into an agreement to sell its interest in EAPC, which held the NOARK interest. This sale was completed on October 31, 2005. The Company received approximately $177.4 million cash proceeds and recognized an after tax gain of approximately $36.7 million from the sale of this business in the fourth quarter. Enogex used approximately $31.9 million of the proceeds to repay principal and accrued interest on long-term debt and approximately $46.7 million to pay taxes associated with EAPC. The balance of the proceeds of approximately $98.8 million will be used to invest, over time, in strategic assets to diversify its asset base.

Capital Expenditures; Improvement Projects.

In 2005, Enogex completed a major upgrade of its information systems that began in 2003. Enogex believes that these upgrades will be a major step towards obtaining the data required to allow it to capture available economic opportunities on its assets, provide improved customer service and enable management to better determine the earnings potential of its various assets and service offerings. One information system implemented provided a single system for pipeline equipment control, data collection, management and measurement of gas volumes and pressures, which has improved Enogex’s access to critical data for daily system management decisions. Another information system implemented, together with the Company’s primary enterprise-wide general ledger software, has been used to accumulate and analyze financial data used in financial reporting. This change in information systems was made to eliminate previous stand alone systems and integrate them into one system.

On a company-wide basis, the Company is the process of implementing an enhanced digital asset mapping technology for both OG&E and Enogex and expects to complete the implementation of this new technology by May 2006. The new system is expected to support a significant increase in the number of members who use this technology in their jobs, expanding the productive use of geographic asset information in a variety of ways, including daily operations, maintenance, budgeting, planning, purchasing and accounting. Also, Enogex began work on a flow data access project called ProductionWatch at the end of the second quarter of 2005. Initial phases of implementation are expected to be completed by mid-year 2006 with the final phases of implementation of this project being completed by the end of 2007. ProductionWatch is a service that provides data (volume, pressure, temperature, etc.) from the Enogex meter to Enogex’s customers for a fee. ProductionWatch data will be available to customers via the internet and it may also be downloaded by customers from Enogex network servers. Such data is attractive because it enables Enogex customers to increase gas production and reduce operating costs. From Enogex’s perspective, ProductionWatch provides Enogex with an additional revenue stream while helping Enogex operate more efficiently.

During 2004, Enogex made improvements to the Stuart Storage Facility which reduced water encroachment in the field. During 2004, approximately $1.9 million of capital investment was made on this project. There were no capital expenditures on this project in 2005. Enogex does not expect any material future expenditures on this water encroachment project.

Transportation and Storage

General. One of Enogex’s primary lines of business is the transportation of natural gas, with current throughput of approximately 1.5 trillion British thermal units (“Btu”) per day. Enogex delivers natural gas to most interstate and intrastate pipelines and end-users connected to its systems from the Arkoma basin of eastern Oklahoma, the Anadarko basin of western Oklahoma and the Panhandle of West Texas. At December 31, 2005, Enogex was connected to 14 other major pipelines at approximately 65 pipeline interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative, CenterPoint Energy Gas Transmission Co., El Paso Natural Gas Pipeline, Enbridge Pipelines, Oneok WesTex Transmission L.P. and Ozark Gas Transmission, L.L.C. Further, Enogex is connected to various end-users including numerous electric generation facilities in Oklahoma that are fueled by natural gas. At December 31, 2005, the net property, plant and equipment balance for Enogex’s transportation and storage business was approximately $522.4 million.

Enogex owns two storage facilities in Oklahoma, the Wetumka Storage Facility and the Stuart Storage Facility. These storage facilities are currently being operated at a working gas level of approximately 23 billion cubic feet (“Bcf”) with an approximate withdrawal capability of 650 million cubic feet per day (“MMcfd”) and similar injection capability. Enogex offers both firm and interruptible storage services to third parties, under Section 311 of the Natural Gas Policy Act (“NGPA”), under terms and conditions specified in its Statement of Operating Conditions (“SOC”) for gas storage and at

market-based rates negotiated with each customer. Both facilities are used to support Enogex’s intrastate transportation and storage services for OG&E.

Enogex offers interruptible Section 311 transportation services as well as both firm and interruptible services to intrastate customers with a majority of transportation revenues derived from firm intrastate contracts. Enogex offers interruptible service to customers when capacity is available.

Enogex provides firm intrastate transportation and storage services to several customers and Enogex’s major customers are OG&E as well as Public Service Company of Oklahoma (“PSO”), the second largest electric utility in Oklahoma, serving the Tulsa market. Enogex provides gas transmission delivery services to all of PSO’s natural gas-fired electric generation units in Oklahoma under a firm intrastate transportation contract. The current PSO contract, which has been extended to January 1, 2007, and the OG&E contract, which expires April 30, 2009, provide for a monthly demand charge plus variable transportation charges (including fuel). As part of the contract with OG&E, Enogex provides additional natural gas storage services for OG&E. Enogex has been providing natural gas storage services since August 2002 when Enogex acquired the Stuart Storage Facility from Central Oklahoma Oil and Gas Corp. (“COOG”). During 2005, 2004 and 2003, Enogex’s revenues from its firm intrastate transportation and storage contracts were approximately $95.0 million, $95.6 million and $92.2 million, respectively.

As previously discussed, in October 2005, Enogex sold its interest in EAPC, which held the NOARK interest.

Relationship with OG&E. From its inception, Enogex has been the transporter of natural gas to OG&E’s natural gas-fired generation facilities. OG&E’s rates are subject to OCC jurisdiction. The OCC issued an order on November 20, 2002 which contained a provision, among other things, that OG&E would consider competitive bidding for gas transportation service to its natural gas-fired generation facilities when the contract with Enogex expired. The term of the then current contract was to expire in April 2004. Following a consideration of competitive bidding by OG&E as required by the prior order from the OCC, the contract with Enogex was amended by an agreement dated May 1, 2003 with no-notice load following requirements and a termination date of April 30, 2009. As part of the contract with OG&E, Enogex provides additional natural gas storage services for OG&E beyond the level and flexibility that was provided previously. Enogex has been providing natural gas storage services since August 2002 when Enogex acquired the Stuart Storage Facility from COOG. The amount collected from OG&E by Enogex under the current contract for transportation services was approximately $34.9 million, $34.3 million and $33.5 million, respectively, during 2005, 2004 and 2003. The amount collected from OG&E by Enogex under the current contract for storage services was approximately $12.7 million, $15.3 million and $11.2 million, respectively, during 2005, 2004 and 2003. In July 2005, OG&E received an OCC order related to its application to recover the costs of gas transportation and storage services provided to OG&E by Enogex pursuant to the contract between OG&E and Enogex. See Note 15 of Notes to Consolidated Financial Statements for a further discussion of this matter.

Competition. Enogex’s transportation and storage assets compete with interstate and other intrastate pipeline and storage facilities in providing transportation and storage services for natural gas. The principal elements of competition are rates, terms of services, flexibility and reliability of service.

Natural gas competes with other forms of energy available to Enogex’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas or other forms of energy as well as weather and other factors affect the demand for natural gas on the Enogex system.

Regulation. The rates charged by Enogex for transporting natural gas on behalf of an interstate natural gas pipeline company or a local distribution company served by an interstate natural gas pipeline company are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years. This rate review may, but will not necessarily, involve an administrative-type hearing before the FERC Staff panel and an administrative appellate review. By offering interruptible Section 311 transportation, the regulatory burden on Enogex is not appreciably increased, but does give Enogex the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase its transportation revenues. Enogex’s approved Section 311 rate structure includes a provision for Enogex to charge a fixed fuel percentage for the fuel usage for natural gas shipped on its system. The fixed fuel percentage is adjusted annually and is in effect for a calendar fuel year (unless Enogex files with the FERC to adjust it more frequently). The mechanism used to recover such fuel is a fuel tracker that establishes a fixed fuel factor (expressed as a percentage of natural gas shipped) that is trued-up over a two year period and based on the value of the gas at the time of usage.

On September 1, 2004, Enogex made a filing at the FERC to revise its previously approved SOC to permit, among other things, the unbundling, effective October 1, 2004, of its previously bundled gathering and transportation services. As a result, effective October 1, 2004, the FERC regulates Enogex’s Section 311 transportation and any regulation of gathering is pursuant to Oklahoma statute.

On September 30, 2004, Enogex made its required triennial filing at the FERC to update its Section 311 maximum interruptible transportation rate. On September 29, 2004, Enogex filed an updated fuel factor with the FERC for the last quarter of 2004. Finally, on November 15, 2004, Enogex filed its annual updated fuel factor for fuel year 2005 (calendar year 2005).

Various parties intervened and protested the four filings but, after three technical conferences and various settlement discussions, reached a unanimous settlement that the FERC approved without modification or condition, by order of September 19, 2005. The Settlement established new maximum interruptible Section 311 zonal rates for an East Zone and a West Zone on the Enogex system, confirmed that Enogex could unbundle its gathering and transportation services and permitted the fuel factor percentages for the last quarter of 2004 and for fuel year 2005 to become effective, as filed. The FERC order concluded all four proceedings which resulted in no refunds being due. Because the FERC requires all intrastate pipeline offering 311 service to file a rate case every three years, Enogex must file its next rate case no later than October 1, 2007.

As required by the fuel tracker provisions of the SOC, Enogex made its annual fuel filing for the 2006 fuel year on November 15, 2005. As agreed in the Settlement, the fuel filing for the first time proposed an East Zone fuel percentage and a West Zone fuel percentage to be recalculated annually to replace the system-wide fuel percentage previously calculated annually for the whole Enogex system. Four parties moved to intervene. One party posed questions about the filing that Enogex answered on January 19, 2006. The FERC Staff later served data requests that Enogex answered on February 17, 2006. The FERC has not yet acted on the filing.

The rates charged by Enogex for transporting natural gas for OG&E and other shippers within Oklahoma are not subject to FERC regulation because they are intrastate transactions. With respect to state regulation, the rates charged by Enogex for any intrastate transportation service have not been subject to direct state regulation by the OCC. The OCC, the APSC and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to Enogex which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service. See Note 15 of Notes to Consolidated Financial Statements for a discussion of the OCC order OG&E received in July 2005 related to the amounts charged OG&E by Enogex for gas transportation and storage services.

Enogex’s pipeline operations are subject to various Oklahoma safety and environmental and non-discriminatory transportation requirements.

Gathering and Processing

General. Natural gas gathering operations are conducted through Enogex Gas Gathering L.L.C. (“Gathering”), and natural gas processing operations are conducted through Enogex Products Corporation (“Products”). The streams of processable natural gas gathered from wells and other sources are gathered through Enogex’s gas gathering systems and delivered to processing plants for the extraction of natural gas liquids. During 2005, Gathering connected 272 new producing wells, located in the Anadarko and Arkoma basins of Oklahoma, to its gathering systems. The Company provides connection, measurement, treating, dehydration and compression services for various types of producing wells owned by various sized producers who are active in the region. Where the quality of natural gas received dictates that removal of natural gas liquids may be in order, such gas is aggregated via the gathering system to the inlet of one or more of the Company’s fleet of processing plants operated by Products. The resulting processed stream of natural gas is then delivered via the Enogex pipeline system to one or more delivery points into the web of transmission pipelines in the region. Products is one of the largest gas processors in Oklahoma, operating six natural gas processing plants with a total inlet capacity of 738 MMcfd. During 2002, Products had ownership interests in two other gas processing plants related to the NuStar Joint Venture, which were sold in February 2003. Products has been active since 1968 in the processing of natural gas and extraction and marketing of natural gas liquids. The liquids extracted include condensate, marketable ethane, propane, butanes and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane. In 2005, approximately 311 million gallons of natural gas liquids were sold. Enogex also had a lease for a small segment of gathering pipeline off of the Palo Duro pipeline system, referred to as the Northeast Lateral. This lease expired February 28, 2005. At December 31, 2005, the net property, plant and equipment balance for Enogex’s gathering and processing business was approximately $352.9 million.

Approximately 20 percent of the commercial grade propane processed at Products’ plants is sold on the local market. The balance of propane and the other natural gas liquids produced by Products are delivered into pipeline facilities of a third party and transported to Conway, Kansas and Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane, which may be optionally produced at all of Products’ plants except one, is sold in the spot market.

During 2002, Enogex initiated steps to decrease the volatility of its earnings stream by reducing its exposure to keep-whole processing arrangements. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis by replacing the Btu of the liquids extracted from the well stream with natural gas at market prices. Therefore, if natural gas prices increase and liquids prices do not increase by a corresponding amount, processing margins are negatively affected. In order to minimize the negative impact on processing margins, ethane and propane are rejected based upon then current market conditions. Exposure to these keep-whole processing arrangements was reduced, but not eliminated, through contract renegotiations and changes in the SOC that provides for a default processing fee in the event the natural gas liquids revenue less the associated fuel and shrinkage costs is negative. In addition, the Company actively monitors current and future commodity prices for opportunities to hedge its processing margin. Enogex uses forward physical sales and financial instruments to capture these spreads.

Enogex is also in the construction phase of a project to expand its gathering pipeline capacity on the west side of its system. This project is expected to be in service before September 2006. This expansion initiative should enable Enogex to benefit from economic growth opportunities in that marketplace.

Competition. Enogex competes with gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, as well as various independent gatherers. In processing and marketing natural gas liquids, Products competes against virtually all other gas processors producing and selling natural gas liquids. Competition for natural gas supply is based on efficiency and reliability of operations, reputation, access to markets and pricing. Enogex believes it will be able to continue to compete effectively.

With respect to the profitability of the natural gas processing industry generally, if the price of natural gas liquids falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to extract certain natural gas liquids. This factor has had a significant adverse impact on the results of Enogex in the past, but, as discussed above, the potential adverse impact has been materially mitigated, but not entirely eliminated. In addition to the commodity pricing impact that affects the entire industry, the profitability of Products is also largely affected by the volume of natural gas processed at its plants which is highly dependent upon the volume and Btu content of natural gas gathered. Generally, if the volume of natural gas gathered increases, then the volume of natural gas liquids extracted by Products should also increase.

Marketing

General. Enogex’s commodity sales and services related to natural gas are conducted primarily through its subsidiary, OGE Energy Resources, Inc. (“OERI”). OERI is engaged in the business of natural gas marketing. OERI provides marketing services to Enogex for natural gas volumes purchased at the wellhead from customers. As a service to the producers on the Enogex system, Enogex may agree to purchase the gas at the wellhead in conjunction with gathering their gas for transportation to other markets. OERI also purchases and sells natural gas pursuant to contracts with Enogex and Products relating to Enogex’s gathering, processing and storage assets. At December 31, 2005, the net property, plant and equipment balance for Enogex’s marketing business was approximately $0.6 million.

OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers and reselling to pipelines, local distribution companies and end-users, including the electric generation sector. The geographic scope of marketing efforts has been focused largely in the mid-continent area of the United States. These markets are natural extensions of OERI’s business on the Enogex system. OERI contracts for pipeline capacity with Enogex and other pipelines to access multiple interconnections with the interstate pipeline system network that moves natural gas from the production basins primarily in the south central United States to the major consumption areas in Chicago, New York and other north central and mid-Atlantic regions of the United States. In 2005, OERI implemented a refocused strategy that seeks to minimize the amount of capital employed and to complement better the natural gas pipeline business. OERI has expanded into the Gulf Coast and Rocky Mountain markets to diversify its business and to facilitate Enogex’s business development efforts.

OERI primarily participates in both intermediate-term markets (less than three years) and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on intermediate-term sales, short-term sales of natural gas are expected to continue to play a critical role in the overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function. OERI’s average daily sales volumes dropped from

approximately 1.8 Bcf in 2004 to 1.4 Bcf in 2005. This reflects selective deal execution to assure adequate margin in light of credit and other risks in the current high commodity price environment. OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by OERI by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the over-the-counter market, subject to daily and monthly trading stop loss limits of $2.5 million and daily value-at-risk limits of $1.5 million in accordance with corporate policies.

OERI and Cheyenne Plains Gas Pipeline Company, L.L.C. are parties to a firm transportation services agreement dated April 14, 2004. The Cheyenne Plains Pipeline provides interstate gas transportation services in Wyoming, Colorado and Kansas with a capacity of 560,000 Dth/day. Effective January 1, 2006, the capacity on the Cheyenne Plains Pipeline increased to 730,000 Dth/day. OERI reserved 60,000 Dth/day of firm capacity on the Cheyenne Plains Pipeline for 10 years. Such reservation provides OERI access to significant additional natural gas supplies in the Rocky Mountain production basins. OERI pays a demand fee of approximately $7.5 million annually for this capacity. OERI incurred a loss of approximately $3.6 million during 2005 related to its Cheyenne Plains’ position as a result of unfavorable market conditions for the capacity primarily due to the earlier than expected in-service date for the project and the associated lack of upstream gas supply and pipeline infrastructure to deliver gas to the Cheyenne hub for 2005. If the market conditions reflected in the current forward market price quotes continue for 2006, OERI expects to record a loss of approximately $1.4 million in 2006.

Competition. OERI competes in marketing natural gas with major integrated oil companies, marketing affiliates of major interstate and intrastate pipelines and commercial banks, national and local natural gas brokers, marketers and distributors for natural gas supplies. Competition for natural gas supplies is based primarily on reputation, credit support, the availability of gathering and transportation to high-demand markets and the ability to obtain a satisfactory price for the producer’s natural gas. Competition for sales to customers is based primarily upon reliability, services offered and the price of delivered natural gas.

For the year ended December 31, 2005, approximately 59 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers. The remaining 41 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2005, approximately 75.9 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately 0.6 percent having less than investment grade ratings. The remaining 23.5 percent of OERI’s exposure is with privately held companies, municipals or cooperatives that were not rated by Standard & Poor’s. OERI applies internal credit analyses and policies to these non-rated companies.

FINANCE AND CONSTRUCTION

Future Capital Requirements

Capital Requirements

The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities (including technology) at Enogex. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional fuel purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

Capital Expenditures

The Company’s current 2006 to 2008 construction program includes continued investment in OG&E’s and Enogex’s assets. OG&E plans to continue to invest in its electric system at a level consistent with 2005. These capital expenditures do not include any capital requirements associated with OG&E’s proposed wind power project pending approval from the OCC. OG&E has approximately 430 MW’s of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) that will expire at the end of 2007, unless extended by OG&E. For one of these QF contracts, OG&E purchases 100 percent of electricity generated by the QF. For the other QF contract, OG&E can purchase up to 17 percent of electricity generated by the QF. In addition, effective September 1, 2004, OG&E entered into a new 15-year power purchase agreement for 120 MW’s with PowerSmith Cogeneration Project, L.P. (“PowerSmith”), in which OG&E purchases 100 percent of electricity generated by PowerSmith. OG&E will continue reviewing all of the

supply alternatives to these expiring QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. Accordingly, OG&E will continue to explore opportunities to build or buy power plants in order to serve its native load. As a result of the high volatility of current natural gas prices and the increase in natural gas prices, OG&E will also assess the feasibility of constructing additional base load coal-fired units as well as wind generation facilities. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital expenditures.

Pension and Postretirement Benefit Plans

During 2005 and 2004, the Company made contributions to its pension plan of approximately $32.0 million and $69.0 million, respectively, to ensure that the pension plan maintains an adequate funded status. During 2006, the Company may contribute up to $90 million to the pension plan. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s pension and postretirement benefit plans.

Future Sources of Financing

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

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. See Note 11 of Notes to Consolidated Financial Statements for a table showing the Company’s lines of credit in place, commercial paper and available cash at December 31, 2005. At December 31, 2005, the Company’s short-term borrowings consisted of commercial paper.

ENVIRONMENTAL MATTERS

Approximately $5.0 million of the Company’s capital expenditures budgeted for 2006 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 $59.7 million during 2006 as compared to approximately $67.0 million in 2005. 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. See Note 14 of Notes to Consolidated Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

EMPLOYEES

The Company and its subsidiaries had 3,044 employees at December 31, 2005.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company’s web site address is www.oge.com. Through the Company’s web site under the heading “Investors”, “SEC Filings,” the Company makes available, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”).

Item 1A. Risk Factors.

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms “OGE Energy”, “we”, “our” and “us” refer to OGE Energy Corp., “OG&E” refers to our subsidiary Oklahoma Gas and

Electric Company and “Enogex” refers to our subsidiary Enogex Inc. and its subsidiaries. In addition to the other information in this 10-K and other documents filed by us and/or our subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS

Our profitability depends to a large extent on the ability of OG&E to fully recover its costs from its customers and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.

We are subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences our operating environment and OG&E’s ability to fully recover its costs from utility customers. With rising fuel costs, recoverability of under recovered amounts from our customers is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to fully recover costs related to providing energy and utility services to our customers. On May 20, 2005, OG&E filed for an $89 million annual rate increase to recover investments in our electric system, including those related to our McClain Plant. Several parties made filings recommending a significantly lower increase and, in certain cases, rate decreases. On December 12, 2005, the OCC issued an order providing for a $42.3 million rate increase in OG&E’s electric rates which became effective in January 2006. This rate order will require us to reduce planned electric system upgrades and expansion projects, and we are considering when to return to the OCC to seek further rate relief. We cannot assure you that the OCC will grant us rate increases in the future or in the amounts we request, and it could instead lower our rates.

In recent years, the regulatory environments in which we operate have received an increased amount of public attention. It is possible that there could be changes in the regulatory environment that would impair our ability to fully recover costs historically absorbed by our customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met.

We are unable to predict the impact on our operating results from the future regulatory activities of any of the agencies that regulate us. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

OG&E’s rates are subject to regulation by the states of Oklahoma and Arkansas, as well as by a federal agency, whose regulatory paradigms and goals may not be consistent.

OG&E is currently a vertically integrated electric utility and most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission and the sale of electricity to wholesale customers subject to rates and other matters approved by the FERC.

OG&E operates in Oklahoma and western Arkansas and is subject to regulation by the OCC and the APSC, in addition to the FERC. Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate may harm our financial condition and results of operations.

Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.

We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife mortality, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.

OG&E’s results of operations could be affected by OG&E’s ability to renegotiate franchise agreements with municipalities and counties in Oklahoma.

OG&E has several franchise agreements with municipalities and counties in Oklahoma and OG&E’s ability to renegotiate these agreements may affect our results of operations and financial position.

The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.

OG&E currently owns and operates transmission facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization (“RTO”) and has transferred operational authority (but not ownership) of OG&E’s transmission facilities to the SPP RTO. The SPP RTO is planning to develop and operate a regional market for trading in electric energy. Because it remains unclear how and when the SPP RTO will implement the market or what new market rules it will establish, we are unable to assess fully the impact that these developments may have on our business. OG&E’s revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP RTO.

OG&E’s Settlement Agreement with the OCC relating to its 2002 rate case targets $75 million of savings over a three-year period from the acquisition of new generation. OG&E may not be able to achieve such targeted savings, in which case, OG&E will be required to credit any unrealized savings to its Oklahoma customers.

As part of OG&E’s settlement agreement in November 2002, OG&E indicated that the acquisition of up to 400 MW’s of new generation through the purchase of a 77 percent in the McClain Plant should provide $75 million of savings to our customers over three years. OG&E also agreed that if it is unable to demonstrate such savings, it will credit its customers any unrealized savings below $75 million. We cannot assure you that OG&E will be able to realize the targeted $75 million of savings to its customers, in which case, OG&E will be required to credit unrealized savings to its Oklahoma customers.

Increased competition resulting from restructuring efforts could have a significant financial impact on us and OG&E and consequently decrease our revenue.

We 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 have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our consolidated financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows. We believe that the prices for electricity and the quality and reliability of our service currently place us in a position to compete effectively in the energy market.

Recent events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, financial condition and access to capital.

As a result of the energy crisis in California during the summer of 2001, the volatility of natural gas prices in North America, the bankruptcy filing by Enron Corporation, accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, companies in the regulated and unregulated utility business have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between corporations and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial condition or access to the capital markets.

As a result of these events, Congress passed the Sarbanes-Oxley Act of 2002. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets and liabilities. These changes in accounting standards could lead to negative impacts on reported earnings or increases in liabilities that could, in turn, affect our reported results of operations.

We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.

We are subject to substantial regulation from federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.

OPERATIONS RISKS

Our results of operations may be impacted by disruptions beyond our control.

We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal for much of our electric generating capacity. We rely on suppliers to deliver coal in accordance with short and long-term contracts. We have certain coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or technical problems which inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Coal delivery may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers. In addition, as agreements with our suppliers expire, we may not be able to enter into new agreements for coal delivery on equivalent terms.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the August 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, as well as seasonal temperature variations may adversely affect our results of operations and financial position.

Weather conditions directly influence the demand for electric power. In OG&E’s service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms and wind storms, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period.

FINANCIAL AND MARKET RISKS

Increasing costs associated with our defined benefit retirement plans, health care plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2005 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain minimum funding levels for our pension plans, we expect to continue to make future contributions to maintain required funding levels. It is our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.

We are a holding company with our primary assets being investments in our subsidiaries.

We are a holding company and thus our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to pay our dividends and service our indebtedness depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. At December 31, 2005, we had outstanding indebtedness and other liabilities of approximately $3.5 billion. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due on our indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiaries on the assets of these subsidiaries will have priority over our claims generally (except to the extent that we may be a creditor of the subsidiaries and our claims are recognized) and claims by our shareowners.

In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions attempt to impose restrictions on the ability of OG&E to pay dividends to us, it could adversely affect our ability to continue to pay dividends.

We and our subsidiaries may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.

The terms of the indentures governing our debt securities do not fully prohibit us or our subsidiaries from incurring additional indebtedness. If we or our subsidiaries are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we and our subsidiaries may be able to incur substantial additional indebtedness. If we or any of our subsidiaries incur additional indebtedness, the related risks that we and they now face may intensify.

Certain provisions in our charter documents and rights plan have anti-takeover effects.

Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporations statute, may have the effect of delaying, deferring or preventing a change in control of OGE Energy. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders’ meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of OGE Energy without stockholder approval, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder’s best interest. Additionally, our rights plan may also delay, defer or prevent a change of control of OGE Energy. Under the rights plan, each outstanding share of common stock has one half of a right attached that trades with the common stock. Absent prior action by our board of directors to redeem the rights or amend the rights plan, upon the consummation of certain acquisition transactions, the rights would entitle the holder thereof (other than the acquiror) to purchase shares of common stock at a discounted price in a manner designed to result in substantial dilution to the acquiror. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock, discourage third party bidders from bidding for us and could significantly impede the ability of the holders of our common stock to change our management.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot assure you that any of our current ratings or our subsidiaries’ will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any future downgrade could increase the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any downgrade could lead to higher borrowing costs and, if below investment grade, could require us to issue guarantees on behalf of Enogex to support some of OERI’s marketing operations.

We are subject to commodity price risk.

We are exposed to commodity price risk in our generation, retail distribution, pipeline and energy trading operations. To minimize the risk of commodity prices, we may enter into physical or financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, distillate fuel oil, electricity, coal and emission allowances. However, financial derivative instrument contracts do not eliminate the risk. Specifically, such risks include commodity price changes, market supply shortages and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts or increased interest expense. However, exposure to commodity price risk related to OG&E’s retail customers is partially mitigated by its fuel adjustment clause, although we cannot assure you that all increases in our commodity prices, including fuel costs, will be completely recovered, or that any such recovery will be timely.

We are also exposed to volatility from our exposure to keep-whole processing arrangements. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis by replacing the Btu of the liquids extracted from the well stream with natural gas at market prices. Therefore, if natural gas prices increase and liquids prices do not increase by a corresponding amount, processing margins are negatively affected. In order to minimize the negative impact on processing margins, ethane and propane are rejected based upon then current market conditions. Exposure to these keep-whole processing arrangements was reduced, but not eliminated, through contract renegotiations and changes in the SOC that provides for a default processing fee in the event the natural gas liquids revenue less the associated fuel and shrinkage costs is negative. In addition, the Company actively monitors current and future commodity prices for opportunities to hedge its processing margin. Enogex uses forward physical sales and financial instruments to capture these spreads. Despite these activities, we cannot assure that our exposure to keep-whole processing arrangements has been eliminated.

We mark our energy trading portfolio to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Market prices are utilized in determining the value of electric energy, natural gas and related derivative commodity instruments. For longer-term positions, which are limited to a maximum of 18 months, and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

We are subject to credit risk.

We are exposed to credit risks in our generation, retail distribution, pipeline and energy trading operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which includes nine generating stations with an aggregate capability of approximately 6,122 MW’s. The following table sets forth information with respect to OG&E’s electric generating facilities, all of which are located in Oklahoma:

						2005	Unit			Station
Station &		Year		Fuel	Unit	Capacity	Capability			Capability
Unit		Installed	Unit Design Type	Capability	Run Type	Factor(A)	(MW)			(MW)
Seminole	1	1971	Steam-Turbine	Gas	Base Load	20.1%	506.0
	1GT	1971	Combustion-Turbine	Gas	Peaking	0.0%(B)		16.0
	2	1973	Steam-Turbine	Gas	Base Load	21.5%	500.5
	3	1975	Steam-Turbine	Gas/Oil	Base Load	27.2%	519.0			1,541.5

Muskogee	3	1956	Steam-Turbine	Gas	Base Load	6.0%	166.0
	4	1977	Steam-Turbine	Coal	Base Load	70.8%	510.5
	5	1978	Steam-Turbine	Coal	Base Load	70.1%	521.6
	6	1984	Steam-Turbine	Coal	Base Load	83.1%	515.0			1,713.1

Sooner	1	1979	Steam-Turbine	Coal	Base Load	87.3%	510.0
	2	1980	Steam-Turbine	Coal	Base Load	73.1%	512.0			1,022.0

Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load	12.6%	168.5
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load	13.4%	234.0
	8	1969	Steam-Turbine	Gas	Base Load	6.7%	387.0
	9	2000	Combustion-Turbine	Gas	Peaking	7.2%(B)			45.5
	10	2000	Combustion-Turbine	Gas	Peaking	7.4%(B)			45.5	880.5

Mustang	1	1950	Steam-Turbine	Gas	Peaking	0.6%(B)			53.0
	2	1951	Steam-Turbine	Gas	Peaking	0.2%(B)			53.0
	3	1955	Steam-Turbine	Gas	Base Load	9.3%	117.5
	4	1959	Steam-Turbine	Gas	Base Load	13.4%	250.0
	5A	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	2.1%(B)			31.0
	5B	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	1.9%(B)			33.0	537.5

Conoco	1	1991	Combustion-Turbine	Gas	Base Load	37.4%			31.5
	2	1991	Combustion-Turbine	Gas	Base Load	40.4%			28.3	59.8

Enid	1	1965	Combustion-Turbine	Gas	Peaking	---(C)			---
	2	1965	Combustion-Turbine	Gas	Peaking	---(C)			---
	3	1965	Combustion-Turbine	Gas	Peaking	---(C)			---
	4	1965	Combustion-Turbine	Gas	Peaking	---(C)			---	---

Woodward	1	1963	Combustion-Turbine	Gas	Peaking	0.2%(B)			12.0	12.0

McClain (D)	1	2001	Combined Cycle	Gas	Base Load	75.9%			355.5	355.5
Total Generating Capability (all stations)											6,121.9

(A)

2005 Capacity Factor = 2005 Net Actual Generation / (2005 Net Maximum Capacity (Nameplate Rating in MW’s) x Period Hours (8,760 Hours)).

(B)

Peaking units, which are used when additional capacity is required, are also necessary to meet the SPP reserve margins.

(C)

These units are currently inactive.

(D)

OG&E owns a 77 percent interest in the 520 MW McClain Plant.

At December 31, 2005, OG&E’s transmission system included: (i) 28 substations with a total capacity of approximately 7.7 million kilo Volt-Amps (“kVA”) and approximately 3,969 structure miles of lines in Oklahoma; and (ii) two substations with a total capacity of approximately 1.9 million kVA and approximately 252 structure miles of lines in Arkansas. OG&E’s distribution system included: (i) 334 substations with a total capacity of approximately 10.0 million kVA, 22,653 structure miles of overhead lines, 2,054 miles of underground conduit and 8,299 miles of underground conductors in Oklahoma; and (ii) 37 substations with a total capacity of approximately 1.6 million kVA, 1,896 structure miles of overhead lines, 257 miles of underground conduit and 478 miles of underground conductors in Arkansas.

At December 31, 2005, Enogex and its subsidiaries owned: (i) approximately 8,300 miles of intrastate gas gathering and transportation pipelines in Oklahoma and Texas; (ii) two natural gas storage fields in Oklahoma operating at a working gas level of approximately 23 Bcf with an approximate withdrawal capability of 650 MMcfd and similar injection capability; and (iii) six operating natural gas processing plants with a total inlet capacity of 738 MMcfd, all located in Oklahoma. The following table sets forth information with respect to Enogex’s natural gas processing plants:

				2005 Inlet	2005 Inlet
Processing	Year		Fuel	Volumes	Capacity
Plant	Installed	Type of Plant	Capability	(MMcfd)	(MMcfd)
Calumet	1969	Lean Oil	Gas	109	250

Canute	1996	Cryogenic Refrigeration	Gas	50	60

Cox City	1994	Cryogenic Refrigeration	Gas	159	180

Harrah	1994	Cryogenic Refrigeration	Gas	24	38

Thomas	1981	Cryogenic Refrigeration	Gas	80	150

Wetumka	1983	Cryogenic Refrigeration	Gas	37	60
				459	738

During the three years ended December 31, 2005, the Company’s gross property, plant and equipment additions were approximately $864.1 million and gross retirements were approximately $226.3 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. The additions during this three-year period amounted to approximately 14.0 percent of total property, plant and equipment at December 31, 2005.

Item 3. Legal Proceedings.

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with 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 set forth below and in Notes 14 and 15 of Notes to Consolidated Financial Statements, 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.

1. The City of Enid, Oklahoma (“Enid”) through its City Council, notified OG&E of its intent to purchase OG&E’s electric distribution facilities for Enid and to terminate OG&E’s franchise to provide electricity within Enid as of June 26, 1998. On August 22, 1997, the City Council of Enid adopted Ordinance No. 97-30, which in essence granted OG&E a new 25-year franchise subject to approval of the electorate of Enid on November 18, 1997. In October 1997, 18 residents of Enid filed a lawsuit against Enid, OG&E and others in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-829-01. Plaintiffs sought a declaration holding that (i) the Mayor of Enid and the City Council breached their fiduciary duty to the public and violated Article 10, Section 17 of the Oklahoma Constitution by allegedly “gifting” to OG&E the option the city held to acquire OG&E’s electric system when the City Council approved the new franchise by Ordinance No. 97-30; (ii) the subsequent approval of the new franchise by the electorate of the City of Enid at the November 18, 1997, franchise election cannot cure the alleged breach of fiduciary duty or the alleged constitutional violation; (iii) violations of the Oklahoma Open Meetings Act occurred and that such violations render the resolution approving Ordinance No. 97-30 invalid; (iv) OG&E’s support of the Enid Citizens’ Against the Government Takeover was improper; (v) OG&E has violated the favored nations clause of the existing franchise; and (vi) the City of Enid and OG&E have violated the competitive bidding requirements found at 11 O.S. 35-201, et seq. Plaintiffs sought money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs alleged that the action of the City Council in approving the proposed franchise allowed the option to purchase OG&E’s property to be transferred to OG&E for inadequate consideration. Plaintiffs demanded judgment for treble the value of the property allegedly wrongfully transferred to OG&E. On October 28, 1997, another resident filed a similar lawsuit against OG&E, Enid and the Garfield County Election Board in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed without prejudice in December 1997. On December 8, 1997, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state claims

upon which relief may be granted. No action has been taken in this case for more than eight years and, for this reason, OG&E is now treating this case as closed.

2. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (United States 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. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with 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 United States Government, alleges: (i) each of the named defendants have improperly or intentionally mismeasured gas (both volume and 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; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) 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 United States Government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the United States Government, decided not to intervene in this action.

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 United States District Court for the District of Wyoming.

In October 2002, the Court granted the Department of Justice’s motion to dismiss certain of Plaintiff’s claims and issued an order dismissing Plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. Discovery is proceeding on limited jurisdictional issues as ordered by the Court. 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 March 17 - 18, 2005. A ruling in this case by the special master was received in May 2005 which dismissed OG&E and all Enogex parties named in these proceedings. This ruling has been appealed to the District Court of Wyoming. An oral argument on this appeal to the District Court was made on December 9, 2005 but there is no ruling in this case to date. 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.

3. Will Price (Price I) – On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. On April 10, 2003 the Court entered an order denying class certification. On May 12, 2003, 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 petition and the court granted the motion on July 28, 2003. In this amended petition, OG&E and Enogex Inc. were omitted from the case. Two subsidiaries of Enogex remain as defendants. The Plaintiffs’ amended petition alleges that approximately 60 defendants, including two Enogex subsidiaries, have improperly measured natural gas. The amended petition reduces the claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative Plaintiffs’ class of only royalty owners; and (4) gas measured in three specific states. Discovery on class certification is proceeding. A hearing on class certification issues was held April 1, 2005. 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.

4. Will Price (Price II) – On May 12, 2003, the Plaintiffs (same as those in Price I above) filed a new class action petition (Price II) in the District Court of Stevens County, Kansas, relating to wrongful Btu analysis against natural gas pipeline owners and operators, naming the same defendants as in the amended petition of the Price I case. Two Enogex subsidiaries were served on August 4, 2003. The Plaintiffs seek to represent a class of only royalty owners either from whom the defendants had purchased natural gas or measured natural gas since January 1, 1974 to the present. The class action petition alleges improper analysis of gas heating content. In all other respects, the Price II petition appears to be the same as the amended petition in Price I. Discovery on class certification is proceeding. A hearing on class certification issues was held April 1, 2005. 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.

5. A Notice of Enforcement Action (“NOE”) by the Texas Natural Resource Conservation Commission (now known as the Texas Commission on Environmental Quality (“TCEQ”)) was issued to Products, a subsidiary of Enogex, by letter dated July 26, 2002. The NOE relates to the operation of a sulfur recovery unit owned and operated by Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) at its Crockett County, Texas natural gas processing facility. Products sold its interest in Belvan in March 2002. The TCEQ’s proposed fine was approximately $0.1 million. Products has requested the TCEQ to issue the NOE in the permitted entity’s name and is waiting for this correction from the TCEQ. Pursuant to the Agreement of Sale and Purchase with the purchaser, Products’ may retain some liability for penalties that Belvan might incur from the NOE not to exceed approximately $0.1 million. This amount is fully reserved on Products’ books.

6. In 1998, Enogex entered into a Storage Lease Agreement (the “Agreement”) with Central Oklahoma Oil and Gas Corp. (“COOG”). In 1999 a dispute arose as to whether the natural gas deliverability for the Stuart Storage Facility was being provided to Enogex by COOG and these issues were submitted to arbitration in the fourth quarter of 2001 resulting in an arbitration award against COOG and in favor of Enogex in the amount of approximately $23.3 million (the “COOG Judgment”).

In 2002, Enogex exercised the asset purchase option provided in the Agreement and title to the Stuart Storage Facility was transferred to Enogex. In addition, under a related transaction, Natural Gas Storage Corporation (“NGSC”), an affiliate of COOG, went into default relating to a $12 million secured loan (“NGSC Loan”) with the Company.

In 2002, a legal proceeding was filed by COOG and NGSC against the Company and Enogex in Texas – Natural Gas Storage Corporation and Central Oklahoma Oil and Gas Corp. v. OGE Energy Corp. and Enogex, Case No. 2002-38894; District Court of Harris County, Texas. COOG and NGSC stated a claim for declaratory judgment and breach of contract, asserting that NGSC was not obligated to make payments on the NGSC Loan. The Company objected to being sued in Texas based on lack of jurisdiction over the Company. Enogex responded to the allegations, asserting that the disputed issues have already been properly determined by the Arbitration Panel and, therefore, such action was improper. In 2003, the Texas Court granted Enogex’s request for arbitration. In 2004, COOG, NGSC, Enogex and the Company submitted remaining issues to a second arbitration panel. The arbitration panel rendered a decision in the Company’s favor for approximately $5.0 million related to the outstanding NGSC Loan (the “NGSC Judgment”). After the arbitration award, the plaintiffs, in the pending Texas action, amended the petition and moved to dismiss Enogex from the suit. The court granted the dismissal by order dated January 26, 2005. On September 30, 2005, an order was entered by the Texas Court disposing of the remaining and entire Texas action based on a lack of jurisdiction.

In 2003, the Company and Enogex brought separate complaints in the Western District of Oklahoma Federal Court against the individual shareholders of COOG and NGSC – Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV-03-0388-L; and OGE Energy Corp. and Enogex Inc. v John C. Thrash, John F. Thrash and Robert R. Voorhees, Jr., Case No. CIV 03-0389-L. The Company and Enogex each stated claims for fraudulent transfer and breach of fiduciary duty. A jury trial was held in 2004 and the jury ruled in favor of the Company and Enogex for approximately $6.6 million (“Thrash Fraudulent Transfer Judgment”). In April 2005, the defendants filed an appeal in the Tenth Circuit Court of Appeals and on September 14, 2005, the defendants posted a cash bond for approximately $6.9 million to stay the execution of the Thrash Fraudulent Transfer Judgment pending appeal. On December 30, 2005, the parties reached a settlement of the Thrash Fraudulent Transfer Judgment, the COOG Judgment, the NGSC Judgment and related matters. The individual defendants agreed to pay approximately $5.2 million (the “Settlement Amount”) from the cash bond paid into the appeal court. In addition, the parties agreed to dismiss the pending appeal of the Thrash Fraudulent Transfer Judgment to the Tenth Circuit. The Settlement Amount has been accounted for as a gain contingency and will be recognized in the Company’s financial statements when the Settlement Amount has been received which is expected in the first quarter of 2006. Upon payment of the Settlement Amount, the Company will consider these matters closed.

7. OG&E was sued by Kaiser-Francis Oil Company in District Court, Blaine County, Oklahoma. This case has been pending for more than 13 years. Plaintiff alleged that OG&E breached the terms of numerous contracts covering approximately 60 wells by failing to purchase gas from Plaintiff in amounts set forth in the contracts. Plaintiff sought $20.0 million in take-or-pay damages and $1.8 million in underpayment damages. Over the objection and unsuccessful appeal by OG&E, Plaintiff was permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleged that OG&E engaged in tortious conduct by, among other things, falsifying documents, sponsoring false testimony and putting forward legal defenses, which were known by OG&E to be without merit. If successful, Plaintiff believed that these

theories could give Plaintiff a basis to seek punitive damages. This lawsuit was stayed from June 2002 through February 2005 during the appeal of a similar case filed by Kaiser-Francis in Grady County, Oklahoma.

On January 3, 2006, the trial court granted OG&E’s motion for partial summary judgment on Plaintiff’s tort claim. This ruling struck from the lawsuit Plaintiff’s claim of (i) approximately $4.7 million in tort damages; and (ii) approximately $11 million in punitive damages. On January 13, 2006, at a court-ordered settlement conference, a settlement was reached in the Blaine County case whereby OG&E agreed to pay $8.9 million to Kaiser-Francis. The suit was dismissed with prejudice on January 18, 2006 and this case is now closed. OG&E believes that the settlement amount is recoverable through its regulated electric rates.

In the similar case in Grady County, Oklahoma, Kaiser-Francis alleged that OG&E breached the terms of several gas purchase contracts in amounts set forth in the contracts. As previously reported in the Company’s Form 10-Q for the quarter ended September 30, 2005, the case was settled and is now closed.

8. OG&E vs. Terra Tech, LLC, District Court of Oklahoma County, State of Oklahoma. Case No. CJ-2004-149. OG&E filed suit against Terra Tech, LLC (“Terra Tech”) alleging that Terra Tech fraudulently, and in breach of contract, submitted invoices for work not performed and materials not used. Terra Tech filed an answer containing a counterclaim against OG&E. Defendant Terra Tech contended that OG&E’s actions constituted a breach of oral contract and failure to pay for work performed in an amount in excess of $10,000. Defendant Terra Tech sought attorney fees. OG&E obtained a partial summary judgment against Terra Tech for approximately $0.2 million, and is pursuing collection on this amount. This case is now closed.

9. On March 8, 2005, Enogex was served with a putative class action filed by G.M. Oil Properties, Inc. in the District Court of Comanche County, Oklahoma. The petition alleges that Enogex exercises a monopoly power with respect to its gathering facilities within the state of Oklahoma. The petition further alleges that, due to the alleged monopoly power, Enogex has caused damage to the plaintiff and other small gas producers and marketers. A settlement of this case has been reached with the named plaintiffs and the case brought by the named plaintiffs will be dismissed with prejudice. Pursuant to the settlement, a certain segment of gathering pipeline will be sold to G.M. Oil Properties with the Company recognizing the resulting gain of less than $0.1 million.

10. On July 22, 2005, Enogex, Products and Gathering along with certain other unaffiliated co-defendants were 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 the Enogex companies, 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. The Enogex companies 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 Enogex companies. The court-established re-filing deadline has been extended by order of the court until May 17, 2006. On September 19, 2005, the co-defendants, BP America, Inc. and BP America Production Co., 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. Based on its investigation to date, the Company believes these claims and cross claims in this lawsuit are without merit and intends to vigorously defend this case.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Executive Officers of the Registrant.

The following persons were Executive Officers of the Registrant as of February 24, 2006:

Name	Age	Title

Steven E. Moore	59	Chairman of the Board, President and Chief Executive Officer

Peter B. Delaney	52	Executive Vice President and Chief Operating Officer

James R. Hatfield	48	Senior Vice President and Chief Financial Officer

Danny P. Harris	46	Senior Vice President – OGE Energy Corp. and President and
		Chief Operating Officer – Enogex Inc.

Carla D. Brockman	46	Vice President - Administration / Corporate Secretary

Steven R. Gerdes	49	Vice President - Utility Operations – OG&E

Gary D. Huneryager	55	Vice President - Internal Audits

Melvin H. Perkins, Jr.	57	Vice President - Transmission - OG&E

Paul L. Renfrow	49	Vice President - Public Affairs

Reid Nuttall	48	Vice President - Enterprise Information and Performance

Scott Forbes	48	Controller and Chief Accounting Officer

Donald R. Rowlett	48	Chief Accounting Policy Officer

Deborah S. Fleming	50	Treasurer

Jerry A. Peace	43	Chief Risk and Compliance Officer

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Delaney, Hatfield, Huneryager, Renfrow, Nuttall, Forbes, Rowlett and Peace, Ms. Brockman and Ms. Fleming are also officers of OG&E. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 18, 2006.

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:

Name		Business Experience

Steven E. Moore	2001 – Present:	Chairman of the Board, President and Chief Executive Officer

Peter B. Delaney	2004 – Present:	Executive Vice President and Chief Operating Officer
	2002 – 2004:	Executive Vice President, Finance and Strategic Planning - OGE Energy Corp. and Chief Executive Officer – Enogex Inc.
	2001 – 2002:	Principal, PD Energy Advisors (consulting firm)

James R. Hatfield	2001 – Present:	Senior Vice President and Chief Financial Officer

Danny P. Harris	2005 – Present:	Senior Vice President – OGE Energy Corp. and President and Chief Operating Officer – Enogex Inc.
	2001 – 2005:	Vice President and Chief Operating Officer – Enogex Inc.
	2001:	Director, Strategic Development – Enogex Inc.

Carla D. Brockman	2005 – Present:	Vice President – Administration / Corporate Secretary
	2002 – 2005:	Corporate Secretary
	2002:	Assistant Corporate Secretary
	2001 – 2002:	Client Manager – Strategic Planning

Steven R. Gerdes	2003 – Present:	Vice President – Utility Operations – OG&E
	2001 – 2003:	Vice President – Shared Services

Gary D. Huneryager	2005 – Present:	Vice President – Internal Audits
	2002 – 2005:	Internal Audit Officer
	2001 – 2002:	Assistant Internal Audit Officer
	2001:	Service Line Director (Business Process Outsourcing) - Arthur Andersen LLP

Melvin H. Perkins, Jr.	2004 – Present:	Vice President – Transmission – OG&E
	2002 – 2003:	Director – Transmission Policy – OG&E
	2001 – 2002:	Manager, Power Delivery Operations – OG&E

Paul L. Renfrow	2005 – Present:	Vice President – Public Affairs
	2002 – 2005:	Director – Public Affairs
	2002:	Manager, Corporate Communications

Reid Nuttall	2006 – Present:	Vice President – Enterprise Information and Performance
	2005 – 2006:	Vice President – Enterprise Architecture – National Oilwell Varco (oil and gas equipment company)
	2001 – 2005:	Chief Information Officer, Vice President – Information Technology – Varco International (oil and gas equipment company)

Scott Forbes	2005 – Present:	Controller and Chief Accounting Officer
	2003 – 2005:	Chief Financial Officer – First Choice Power (electric utility)
	2002 – 2005:	Senior Vice President and Chief Financial Officer – Texas New Mexico Power Company
	2001 – 2002:	Vice President – Chief Accounting and Information Officer Texas New Mexico Power Company (electric utility)

Donald R. Rowlett	2005 – Present:	Chief Accounting Policy Officer
	2001 – 2005:	Vice President and Controller

Deborah S. Fleming	2003 – Present:	Treasurer
	2001 – 2003:	Assistant Treasurer – Williams Cos. Inc. (energy company)

Jerry A. Peace	2004 – Present:	Chief Risk and Compliance Officer
	2002 – 2004:	Chief Risk Officer
	2001 – 2002:	Director, Options Trading – Enogex Inc.
	2001:	Director, Structured Services – Enogex Inc.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s Common Stock is listed for trading on the New York and Pacific Stock Exchanges under the ticker symbol “OGE.” Quotes may be obtained in daily newspapers where the common stock is listed as “OGE Engy” in the New York Stock Exchange listing table. The following table gives information with respect to price ranges, as reported in The Wall Street Journal as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown.

	Dividend	Price
2004	Paid	High	Low

First Quarter	$ 0.3325	$ 26.70	$ 23.03

Second Quarter	0.3325	26.80

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number 1-12579