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, 2008

o 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: 1-1097

OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma		73-0382390
(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: None
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 o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o 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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this Chapter) 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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer o	Accelerated Filer o
Non-Accelerated Filer x (Do not check if a smaller reporting company)	Smaller reporting company o

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

At June 30, 2008, 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 $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.

At January 31, 2009, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

DOCUMENTS INCORPORATED BY REFERENCE

None

Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2008

TABLE OF CONTENTS

	Page
FORWARD-LOOKING STATEMENTS	1

Part I
Item 1. Business	2
The Company	2
General	3
Regulation and Rates	5
Rate Structures	8
Fuel Supply and Generation	9
Environmental Matters	10
Finance and Construction	12
Employees	14
Access to Securities and Exchange Commission Filings	14

Item 1A. Risk Factors	14

Item 1B. Unresolved Staff Comments	19

Item 2. Properties	20

Item 3. Legal Proceedings	21

Item 4. Submission of Matters to a Vote of Security Holders	23
Executive Officers of the Registrant	24

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities	27

Item 6. Selected Financial Data	27

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	46

Item 8. Financial Statements and Supplementary Data	49

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	95

Item 9A. Controls and Procedures	95

Item 9B. Other Information	98

Part III
Item 10. Directors, Executive Officers and Corporate Governance	98

Item 11. Executive Compensation	98

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters	98

Item 13. Certain Relationships and Related Transactions, and Director Independence	98

Item 14. Principal Accounting Fees and Services	98

Part IV
Item 15. Exhibits, Financial Statement Schedules	99

Signatures	107

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

•

general economic conditions, including the availability of credit, access to existing lines of credit, actions of rating agencies and their impact on capital expenditures;

•

Oklahoma Gas and Electric Company’s (the “Company”), a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”), and OGE Energy’s ability to access the capital markets and obtain financing on favorable terms;

•

prices and availability of electricity, coal and natural gas;

•

business conditions in the energy industry;

•

competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;

•

unusual weather;

•

availability and prices of raw materials for current and future construction projects;

•

federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;

•

environmental laws and regulations that may impact the Company’s operations;

•

changes in accounting standards, rules or guidelines;

•

the discontinuance of regulated accounting principles under Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation”;

•

creditworthiness of suppliers, customers and other contractual parties; and

•

other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission (“SEC”) including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to this Form 10-K.

PART I

Item 1. Business.

THE COMPANY

Introduction

The Company generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy which 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 was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. The Company’s principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.

Company Strategy

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

The Company has been focused on increased investment at the utility to improve reliability and meet load growth, leverage unique geographic position to develop renewable energy resources for wind and transmission, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, the Company has taken, or has committed to take, the following actions:

•

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

•

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

•

OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture in July 2008 to construct high-capacity transmission line projects in western Oklahoma which is intended to allow the companies to lead development of renewable wind with the planned transmission construction from Woodward northwest to Guymon in the Oklahoma Panhandle and from Woodward north to the Kansas border;

•

The Company purchased a 51 percent interest in the 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (the “Redbud Facility”) in September 2008;

•

The Company issued a request for proposal (“RFP”) for wind power in December 2008 for up to 300 MWs of new capability which the Company intends to add to its power-generation portfolio no later than the end of 2010; and

•

The Company’s construction initiative from 2009 to 2014 includes approximately $2.7 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. This construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure.

The Company continues to pursue additional renewable energy and the construction of associated transmission facilities required to support this renewable expansion. In 2008, the Company established a “Quick Start” Demand Side Management program to encourage more efficient use of electricity. The Company also announced a “Positive Energy SmartPower” initiative (commonly referred to in the industry as “Smart Grid” technologies) that will empower customers to proactively manage their energy consumption during periods of peak demand. If these initiatives are successful, the Company believes it may be able to defer the construction of any incremental fossil fuel generation capacity until 2020.

The increase in wind power generation and the building of the transmission lines are subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the Southwest Power Pool (“SPP”). Other projects involve installing new emission-control and monitoring equipment at the Company’s existing power plants to help meet the Company’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 14 of Notes to Financial Statements.

General

The Company furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. At December 31, 2008, four other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from the Company for resale. The service area 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 the Company serves, 243 are located in Oklahoma and 26 in Arkansas. The Company derived approximately 89 percent of its total electric operating revenues for the year ended December 31, 2008 from sales in Oklahoma and the remainder from sales in Arkansas.

The Company’s system control area peak demand as reported by the system dispatcher during 2008 was approximately 6,472 MWs on August 4, 2008. The Company’s load responsibility peak demand was approximately 6,054 MWs on August 4, 2008. As reflected in the table below and in the operating statistics that follow, there were approximately 26.8 million megawatt-hour (“MWH”) sales to the Company’s customers (“system sales”) in 2008 and 26.4 million MWH system sales in both 2007 and 2006. Variations in system sales for the three years are reflected in the following table:

		2008 vs. 2007		2007 vs. 2006		2006 vs. 2005
Year ended December 31 (In millions)	2008	Increase	2007	Increase	2006	Increase
System Sales (A)	26.8	1.5%	26.4	---%	26.4	1.5%

(A)	Sales are in millions of MWHs.

The Company 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.

Besides competition from other suppliers or marketers of electricity, the Company 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 14 of Notes to 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)		2008		2007		2006

ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)		25.7		23.8		24.6
Purchased		4.3		5.2		3.9
Total generated and purchased		30.0		29.0		28.5
Company use, free service and losses		(1.8)		(1.9)		(2.1)
Electric energy sold		28.2		27.1		26.4

ELECTRIC ENERGY SOLD (Millions of MWH)
Residential		9.0		8.7		8.7
Commercial		6.5		6.3		6.2
Industrial		4.0		4.2		4.4
Oilfield		2.9		2.8		2.7
Public authorities and street light		3.0		3.0		2.9
Sales for resale		1.4		1.4		1.5
System sales		26.8		26.4		26.4
Off-system sales		1.4		0.7		---
Total sales		28.2		27.1		26.4

ELECTRIC OPERATING REVENUES (In millions)
Residential	$	751.2	$	706.4	$	698.8
Commercial		479.0		450.1		428.3
Industrial		219.8		221.4		215.7
Oilfield		151.9		140.9		129.3
Public authorities and street light		190.3		181.4		171.0
Sales for resale		64.9		68.8		65.4
Provision for rate refund		(0.4)		0.1		(0.9)
System sales revenues		1,856.7		1,769.1		1,707.6
Off-system sales revenues		68.9		35.1		2.7
Other		33.9		30.9		35.4
Total Electric Operating Revenues	$	1,959.5	$	1,835.1	$	1,745.7

ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential		659,829		653,369		647,548
Commercial		85,030		83,901		82,974
Industrial		3,086		3,142		3,181
Oilfield		6,424		6,324		6,324
Public authorities and street light		15,670		15,446		14,769
Sales for resale		49		52		44
Total		770,088		762,234		754,840

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,145.05	$	1,086.03	$	1,084.31
Average annual use (kilowatt-hour (“KWH”))		13,659		13,325		13,526
Average price per KWH (cents)	$	8.38	$	8.15	$	8.02

Regulation and Rates

The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’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 the Company’s facilities and operations. For the year ended December 31, 2008, approximately 88 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and three percent to the FERC.

The OCC issued an order in 1996 authorizing the Company to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with the Company; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and (iii) OGE Energy refrain from pledging Company 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 OGE Energy and its affiliates as the FERC deems relevant to costs incurred by the Company or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

The Company 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 the Company due to the significant problems faced by other states in their electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which the Company conducts its business. These developments at the Federal and state levels are described in more detail in Note 14 of Notes to Financial Statements.

Recent Regulatory Matters

Acquisition of Redbud Power Plant. On January 21, 2008, the Company entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which were indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, the Company agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which owned the Redbud Facility, for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.

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

The transactions described above were subject to an order from the FERC authorizing the contemplated transactions and an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions.

Company’s completion of these upgrades. The Company is required to file quarterly updates describing the progress of the transmission upgrades, the first of which was filed December 16, 2008. The Company also must notify the FERC of any change in circumstances regarding these projects. During the approximately 27-month period required to construct the transmission upgrades, the FERC did not require any interim mitigation beyond the limits of the Company’s market-based rate authority and the SPP market monitoring programs currently in place. In addition, the FERC found that the proposed transaction would have no adverse effects on vertical market power, on wholesale rates, or on state or Federal regulation. The FERC also determined that the transaction presented no cross-subsidy concerns. Finally, the FERC rejected various arguments raised by AES Shady Point that sought to expand the scope of the FERC proceeding or to impose additional conditions on the Redbud acquisition. On September 24, 2008, the OCC issued an order approving the Redbud acquisition. The Company closed on the Redbud acquisition on September 29, 2008. The Company implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes.

Cancelled Red Rock Power Plant and Storm Cost Recovery Rider. On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, the Company requested authorization to sell approximately $14.7 million of its sulfur dioxide (“SO2”) allowances and to retain 100 percent of the proceeds to offset the $14.7 million of Red Rock costs. Under a prior order of the OCC, 90 percent of the proceeds from sales of SO2 allowances were to be credited to ratepayers. Any portion of the $14.7 million of deferred costs that the OCC did not approve for recovery by the Company was to be expensed. In its response to the Company’s Red Rock cost recovery application, the OCC Staff recommended, among other things, that the Company sell SO2 allowances and retain 100 percent of the proceeds from the sale to be used to offset the Company’s December 2007 ice storm costs. These ice storm costs were included as part of the regulatory asset balance of approximately $35.9 million at December 31, 2007 (see Note 1), in accordance with a prior order of the OCC, pending recovery in a future rate case. On June 27, 2008, the Company filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, the Company will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with the Company’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date the Company begins to recover the regulatory asset through the base rates established in the Company’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in the Company’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover the Company’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess SO2 allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by the Company and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, the Company wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Financial Statements.

Renewable Energy Filing. The Company announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued an RFP to wind developers for construction of up to 300 MWs of new capability. The Company intends to add the new capacity to its power-generation portfolio no later than the end of 2010. See discussion of the Company proposed wind power project below.

The Company filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma at a cost of approximately $211 million. This transmission line is a critical first step to increased wind development in western Oklahoma. In the application, the Company also requested authorization to implement a recovery rider to be effective when the transmission line is completed and in service, which is expected during 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to the Company’s Oklahoma customers. On July 11, 2008, the OCC Staff filed responsive testimony recommending approval of the Company’s renewable plan and the Oklahoma Industrial Energy Consumers opposed the Company’s request. A settlement agreement was signed by all parties in the matter on July 31, 2008. Under the terms of the settlement agreement, the parties agreed that the Company will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and allowance for funds used during construction (“AFUDC”) when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million the Company be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above. On February 2, 2009, the Company received SPP approval to begin construction of the transmission line and the associated Woodward Extra High Voltage substation.

Arkansas Rate Case Filing. On August 29, 2008, the Company filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that the Company can reliably meet growing customer demand for electricity, and a return on equity of 12.25 percent. In January 2009, the APSC Staff recommended a $12.0 million rate increase based on a 10.5 percent return on equity. The Attorney General’s consultant recommended a return on equity at the current authorized level of 10.0 percent and stated that his analysis identified at least $10.9 million in reductions to the Company’s rate increase request. A hearing is scheduled for April 7, 2009. An order from the APSC is expected in June 2009, with new rates targeted for implementation in July 2009.

2009 Oklahoma Rate Case Filing. Beginning in October 2008, the Company began developing a rate case filing for the Oklahoma jurisdiction. On January 20, 2009, the Company notified the OCC that it will make its planned Oklahoma rate case filing on or about February 26, 2009. The Company is finalizing the preparation of the rate case and expects to request an increase of between $100 million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest.

Proposed Wind Power Project. The Company signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the future OU Spirit wind project in western Oklahoma. The Company will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

See Note 14 of Notes to Financial Statements for further discussion of these matters, as well as a discussion of additional regulatory matters, including, among other things, review of the Company’s fuel adjustment clause, the Company FERC formula rate filing, the Company 2008 storm cost filing, national energy legislation and state legislative initiatives.

Regulatory Assets and Liabilities

The Company, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71. 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.

At December 31, 2008 and 2007, the Company had regulatory assets of approximately $464.3 million and $330.7 million, respectively, and regulatory liabilities of approximately $164.0 million and $148.2 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.

As discussed in Note 14 of Notes to Financial Statements, legislation was enacted in the 1990’s for Oklahoma that was to restructure the electric utility industry in that state. The 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 the Company’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect the Company’s electric transmission and distribution assets and the Company 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.

Rate Structures

Oklahoma

The Company’s standard tariff rates include a cost-of-service component (including an authorized return on capital) plus an fuel adjustment clause mechanism that allows the Company to pass through to customers variances (either positive or negative) in the actual cost of fuel as compared to the fuel component in the Company’s most recently approved rate case.

The Company offers several alternate 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 the Company’s rate case completed in December 2005. A second tariff rate option provides a “renewable energy” resource to the Company’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and is available as a voluntary option to all of the Company’s Oklahoma retail customers. The Company’s ownership and access to wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers and provides the customers with a means to reduce their exposure to increased prices for natural gas used by the Company as boiler fuel. 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 the Company’s commercial and industrial customers is a voluntary load curtailment program. This program provides customers with the opportunity to curtail usage on a voluntary basis when the Company’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 the Company’s other rate choices, provide many tariff options for the Company’s Oklahoma retail customers. The Company’s rate choices, 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 not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. There was a gain from the GFB option of approximately $3.0 million, $4.2 million and $0.6 million, respectively, in 2008, 2007 and 2006. Revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose alternative rate options.

The Company also has two additional rate classes, Public Schools-Demand and Public Schools Non-Demand. These two classes of service will provide the Company flexibility to provide targeted programs for load management to public schools and their unique usage patterns. The Company also created service level fuel differentiation that allows customers to pay fuel costs that better reflect operational energy losses related to a specific service level. Lastly, the Company also implemented a military base rider that demonstrates Oklahoma’s continued commitment to our military partners.

Fuel Supply and Generation

During 2008, approximately 68 percent of the Company-generated energy was produced by coal-fired units, 30 percent by natural gas-fired units and two percent by wind-powered units. Of the Company’s 6,781 total MW capability reflected in the table under Item 2. Properties, approximately 4,119 MWs, or 61 percent, are from natural gas generation, approximately 2,542 MWs, or 37 percent, are from coal generation and approximately 120 MWs, or two percent, are from wind generation. Though the Company 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. Over the last five years, the weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

Year ended December 31	2008	2007	2006	2005	2004
Coal	$ 1.11	$ 1.10	$ 1.10	$ 0.98	$ 1.00
Natural Gas	$ 8.40	$ 6.77	$ 7.10	$ 8.76	$ 6.57
Weighted Average	$ 3.30	$ 3.13	$ 2.98	$ 3.21	$ 2.69

The increase in the weighted average cost of fuel in 2008 as compared to 2007 was primarily due to increased natural gas prices partially offset by decreased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2007 as compared to 2006 was primarily due to increased natural gas volumes. The decrease in the weighted average cost of fuel in 2006 as compared to 2005 was primarily due to decreased natural gas prices partially offset by increased amounts of natural gas being burned. 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. 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 the Company’s fuel adjustment clauses that are approved by the OCC and the APSC. See Note 13 of Notes to Financial Statements for a discussion of new and pending coal transportation contracts that will increase the Company’s delivered coal prices.

Coal

All of the Company’s coal-fired units, with an aggregate capability of approximately 2,542 MWs, are designed to burn low sulfur western coal. The Company purchases coal primarily under contracts expiring in years 2010 and 2011. During 2008, the Company purchased approximately 10.5 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.3 percent and can be burned in these units under existing Federal, state and local environmental standards (maximum of 1.2 lbs. of SO2 per MMBtu) without the addition of SO2 removal systems. Based upon the average sulfur content, the Company’s coal units have an approximate emission rate of 0.52 lbs. of SO2 per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 13 of Notes to Financial Statements.

The Company 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 13 of Notes to Financial Statements for a discussion of environmental matters which may affect the Company in the future.

Natural Gas

In August 2008, the Company issued an RFP for gas supply purchases for periods from November 2008 through March 2009, which accounted for approximately 15 percent of its projected 2009 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2009. Additional gas supplies to fulfill the Company’s remaining 2009 natural gas requirements will be acquired through additional RFPs in early to mid-2009, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.

In 1993, the Company began utilizing a natural gas storage facility for storage services that allowed the Company to maximize the value of its generation assets. Storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with the Company. At December 31, 2008, the Company had approximately 1.9 million MMBtu’s in natural gas storage that it acquired for approximately $11.5 million.

Wind

The Company’s current wind power portfolio includes the 120 MW Centennial wind farm placed in service in January 2007 as well as access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract the Company entered into with FPL Energy in 2003.

The Company announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued an RFP to wind developers for construction of up to 300 MWs of new capability. The Company intends to add the new capacity to its power-generation portfolio no later than the end of 2010.

The Company signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the future OU Spirit wind project in western Oklahoma. The Company will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

Safety and Health Regulation

The Company is subject to a number of Federal and state laws and regulations, including the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state statutes, whose purpose is to protect the safety and health of workers. In addition, the OSHA hazard communication standard, the U.S. Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

ENVIRONMENTAL MATTERS

General

The activities of the Company are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations can restrict or impact the Company’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment. The Company handles some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”) and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes.

The Company believes that its operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing Federal, state and local environmental laws and regulations will not have a material adverse effect on their business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, the Company cannot assure that future events, such as changes in existing laws, the promulgation of new laws, or the

development or discovery of new facts or conditions will not cause it to incur significant costs. Approximately $1.0 million and $31.5 million, respectively, of the Company’s capital expenditures budgeted for 2009 and 2010 are to comply with environmental laws and regulations. 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 $35.7 million during 2009 as compared to approximately $37.1 million during 2008. Management 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 13 of Notes to Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

Hazardous Waste

The Company’s operations generate hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 (“RCRA”) as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste. These laws impose strict “cradle to grave” requirements on generators regarding their treatment, storage and disposal of hazardous waste. The Company routinely generates small quantities of hazardous waste throughout its system that include, but are not limited to, waste paint, spent solvents, rechargeable batteries and mercury-containing lamps. These wastes are treated, stored and disposed off-site at facilities that are permitted to manage them. Occasionally, larger quantities of hazardous wastes are generated as a result of power generation-related activities and these larger quantities are managed either on-site or off-site. Nevertheless, through its waste minimization efforts, the majority of the Company’s facilities remain conditionally exempt small quantity generators of hazardous waste.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) (also known as “Superfund”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Because the Company utilizes various products and generates wastes that either are or otherwise contain CERCLA hazardous substances, the Company could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause any significant impact to the Company.

Air Emissions

The Company’s operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Company obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, install emission control equipment or subject the Company to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. The Company likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. See Note 13 of Notes to Financial Statements for a discussion of potentially significant environmental capital expenditures related to air emissions.

Water Discharges

The Company’s operations are subject to the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an

appropriately issued permit. Any unpermitted release of pollutants from the Company’s power plants, pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations. See Note 13 of Notes to Financial Statements for a discussion of water intake matters.

Other Laws and Regulations

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. For instance, at least nine states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont) and five states in the West (Arizona, California, New Mexico, Oregon and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The enactment of climate control laws or regulations that restrict emissions of greenhouse gases in areas in which the Company conducts business could have an adverse effect on its operations and demand for its services or products. The Company reports quarterly its carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions.

FINANCE AND CONSTRUCTION

Future Capital Requirements

Capital Requirements

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities in its electric utility business. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. However, OGE Energy’s and the Company’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements which bear a higher interest rate and a minimum 30-day maturity compared to commercial paper which had historically been available at lower interest rates and on a daily basis. OGE Energy and the Company expect to repay the borrowings under their revolving credit agreements and begin utilizing commercial paper in the commercial paper market when available. 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

Notes to Financial Statements, due to comments from the EPA that the Company’s proposed initial BART compliance plan would not satisfy the applicable requirements, the Company completed additional analysis. On May 30, 2008, the Company filed the results with the Oklahoma Department of Environmental Quality (“ODEQ”) for the affected generating units. In the May 30, 2008 filing, the Company indicated its intention to install low nitrogen oxide (“NOX”) combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. The Company believes that these control measures will achieve visibility improvements in a cost-effective manner. The Company did not propose the installation of scrubbers at its four coal-fired generating units because the Company concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. The Company previously reported an expectation that a compliance plan would be approved by the EPA by December 31, 2008; however, submission of the overall compliance plan by the ODEQ (which will include the Company’s compliance plan previously submitted to the ODEQ) has been delayed and the current timing of the EPA approval cannot be reasonably predicted. In a letter dated November 4, 2008, the EPA notified the ODEQ that they had completed their review of BART applications for all affected sources in Oklahoma, which included the Company. The EPA did not approve or disapprove the applications, however, additional information was requested from the ODEQ by the EPA regarding the Company’s plan. The Company cannot predict what action the EPA or the ODEQ will take in response to its May 30, 2008 filing or the November 4, 2008 letter from the EPA. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. Due to this uncertainty regarding BART costs, the Company has excluded any BART costs from the foregoing capital expenditure estimates. The Company also has approximately 440 MWs of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. The Company will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

Pension and Postretirement Benefit Plans

During both 2008 and 2007, OGE Energy made contributions to its pension plan of approximately $50.0 million to help ensure that the pension plan maintains an adequate funded status, of which approximately $47.0 million and $38.3 million, respectively, were the Company’s portion. During 2009, OGE Energy may contribute up to $50.0 million to its pension plan, of which approximately $47.0 million is expected to be the Company’s portion. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of OGE Energy’s pension and postretirement benefit plans.

Future Sources of Financing

Management expects that cash generated from operations and proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) 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. At December 31, 2008 and 2007, the Company had no outstanding borrowings under its revolving credit agreement and no outstanding commercial paper borrowings. OGE Energy’s and the Company’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis. However, in late 2008, OGE Energy’s and the Company’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, the Company repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. The Company intends to utilize commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreement and begin utilizing the commercial paper market when available. Also, the Company has the necessary regulatory approvals to incur up to $800

million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31, 2010. See Note 11 of Notes to Financial Statements for a discussion of OGE Energy’s and the Company’s short-term debt activity.

EMPLOYEES

The Company had 2,113 employees at December 31, 2008.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

OGE Energy’s web site address is www.oge.com. Through OGE Energy’s web site under the heading “Investors”, “SEC Filings,” OGE Energy makes available, free of charge, OGE Energy’s and the Company’s 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 SEC.

Item 1A. Risk Factors.

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms “we”, “our” and “us” refer to Oklahoma Gas and Electric Company and “OGE Energy” refers to OGE Energy. In addition to the other information in this Annual Report on Form 10-K and other documents filed by us with the SEC from time to time, the following factors should be carefully considered in evaluating the Company. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on our behalf. 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 our ability to fully recover our costs from our customers and there may be changes in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to fully recover our 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 we operate 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.

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. Although the Company has several rate proceedings currently pending, and expects to file a general rate case in Oklahoma shortly, we cannot assure that the OCC, APSC and the FERC will grant us rate increases in the future or in the amounts we request, and they could instead lower our rates.

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.

Our 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.

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

We operate in Oklahoma and western Arkansas and are 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 position 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.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

There also is growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Federal Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and Federal action on climate change issues. We report quarterly our carbon dioxide emissions from our generating stations under the EPA’s acid rain program and are continuing to evaluate various options for reducing, avoiding, off-setting or sequestering our carbon dioxide emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. See Note 13 of Notes to Financial Statements for a further discussion.

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of our facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. We currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This could adversely affect our results of operations and financial position. While we may seek to limit the impact of any denied recovery by attempting to

reduce the scope of our capital investment, there can no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

Our planned capital investment program coincides with a material increase in the historic prices of the fuels used to generate electricity. Many of our jurisdictions have fuel clauses that permit us to recover these increased fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery,in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates. Any such limitation could adversely affect our results of operations and financial position.

The regional power market in which we operate has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.

We currently own and operate transmission and generation facilities as part of a vertically integrated utility. We are a member of the SPP regional transmission organization (“RTO”) and have transferred operational authority (but not ownership) of our transmission facilities to the SPP RTO. The SPP RTO implemented a regional energy imbalance service market on February 1, 2007. We have participated, and continue to participate, in the SPP energy imbalance service market to aid in the optimization of our physical assets to serve our customers. We have not participated in the SPP energy imbalance service market for any speculative trading activities. The SPP purchases and sales are not allocated to individual customers. We record the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in our Financial Statements. Our revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP RTO.

Increased competition resulting from restructuring efforts could have a significant financial impact on us 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 possible impairments 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 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 financial position, results of operations or cash flows.

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 position, cash flows and access to capital.

As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those 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 companies 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 position, cash flows or access to the capital markets. 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, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.

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.

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with significant monetary penalties. The FERC has approved the North American Electric Reliability Corporation (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. It is our intent to comply with all applicable reliability rules and expediently correct a violation should it occur. We are subject to a NERC readiness evaluation and compliance audit every three years and cannot predict the outcome of those audits.

OPERATIONAL 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 that 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 position and results of operations.

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our financial position, results of operations and cash flows.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be

known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.

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

Weather conditions directly influence the demand for electric power. In our 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 RISKS

Market performance, increased retirements, changes in retirement plan regulations and 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 retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2008, we expect to continue to make future contributions to maintain required funding levels; however, as our plans have experienced adverse market returns on investments in 2008 due to the recent turmoil in the financial markets, this could cause our future contributions to rise substantially over historical 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.

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions, introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants.

Many of the changes enacted as part of the Pension Protection Act were required to be implemented as of the first plan year beginning in 2008. While the Company generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. See Note 12 of Notes to Financial Statements for a further discussion of changes made to the Company’s plans in order to comply with the Pension Protection Act.

All employees hired prior to February 1, 2000 participate in defined benefit and postretirement plans. If these employees retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our results of operations and financial position. Those assumptions are outside of our control.

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 face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.

Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, approximately 33 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

We 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 from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we and they now face may intensify.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.

We cannot assure that any of our current ratings 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 so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the recent market turmoil. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit.

We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.

We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that customers and counterparties that owe us money or energy will breach their obligations. If such parties 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.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We have revolving credit agreements for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:

•

the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;

•

a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and

•

our debt levels may limit our flexibility in responding to changing business and economic conditions.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

The Company owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included ten generating stations with an aggregate capability of approximately 6,781 MWs at December 31, 2008. The following table sets forth information with respect to the Company’s electric generating facilities, all of which are located in Oklahoma.

						2008		Unit	Station
Station &		Year		Fuel	Unit	Capacity		Capability	Capability
Unit		Installed	Unit Design Type	Capability	Run Type	Factor (A)		(MW)	(MW)
Muskogee	3	1956	Steam-Turbine	Gas	Base Load	10.9%		171
	4	1977	Steam-Turbine	Coal	Base Load	78.0%		477
	5	1978	Steam-Turbine	Coal	Base Load	62.5%		517
	6	1984	Steam-Turbine	Coal	Base Load	73.2%		502	1,667

Seminole	1	1971	Steam-Turbine	Gas	Base Load	19.2%		464
	1GT	1971	Combustion-Turbine	Gas	Peaking	---%	(B)	17
	2	1973	Steam-Turbine	Gas	Base Load	27.6%		494
	3	1975	Steam-Turbine	Gas/Oil	Base Load	78.7%		502	1,477

Sooner	1	1979	Steam-Turbine	Coal	Base Load	87.4%		522
	2	1980	Steam-Turbine	Coal	Base Load	77.5%		524	1,046

Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load	22.2%		171
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load	19.2%		227
	8	1969	Steam-Turbine	Gas	Base Load	3.6%		380
	9	2000	Combustion-Turbine	Gas	Peaking	3.1%	(B)	46
	10	2000	Combustion-Turbine	Gas	Peaking	3.2%	(B)	46	870

Mustang	1	1950	Steam-Turbine	Gas	Peaking	0.6%	(B)	54
	2	1951	Steam-Turbine	Gas	Peaking	0.6%	(B)	50
	3	1955	Steam-Turbine	Gas	Base Load	17.8%		113
	4	1959	Steam-Turbine	Gas	Base Load	25.2%		251
	5A	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	0.4%	(B)	32
	5B	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	0.5%	(B)	32	532

Redbud (C)	1	2003	Combined Cycle	Gas	Base Load	32.8%		163
	2	2003	Combined Cycle	Gas	Base Load	32.8%		163
	3	2003	Combined Cycle	Gas	Base Load	32.7%		163
	4	2003	Combined Cycle	Gas	Base Load	32.7%		163	652

McClain (D)	1	2001	Combined Cycle	Gas	Base Load	55.9%		363	363

Woodward	1	1963	Combustion-Turbine	Gas	Peaking	0.1%	(B)	10	10

Enid	1	1965	Combustion-Turbine	Gas	Peaking	0.1%		11
	2	1965	Combustion-Turbine	Gas	Peaking	---%		11
	3	1965	Combustion-Turbine	Gas	Peaking	---%		11
	4	1965	Combustion-Turbine	Gas	Peaking	0.1%		11	44
Total Generating Capability (all stations, excluding winds station)									6,661

						2008	Unit		Station
		Year		Number of	Fuel	Capacity	Capability		Capability
	Station	Installed	Location	Units	Capability	Factor (A)	(MW)		(MW)
	Centennial	2007	Woodward, OK	80	Wind	40.7%	1.5		120.0
Total Generating Capability (wind station)								120.0

(A) 2008 Capacity Factor = 2008 Net Actual Generation / (2008 Net Maximum Capacity (Nameplate Rating in MWs) 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) The original units at the Redbud Facility were installed in 2003. In September 2008, the Company purchased a 51 percent ownership interest in the Redbud Facility. The capacity factor for the Redbud Facility shown above represents the capacity factor since the Company’s ownership.

(D) Represents the Company’s 77 percent ownership interest in the McClain Plant.

At December 31, 2008, the Company’s transmission system included: (i) 48 substations with a total capacity of approximately 9.9 million kilo Volt-Amps (“kVA”) and approximately 4,029 structure miles of lines in Oklahoma; and (ii) seven substations with a total capacity of approximately 2.5 million kVA and approximately 259 structure miles of lines in Arkansas. The Company’s distribution system included: (i) 348 substations with a total capacity of approximately 8.8 million kVA, 24,472 structure miles of overhead lines, 1,591 miles of underground conduit and 9,933 miles of underground conductors in Oklahoma; and (ii) 37 substations with a total capacity of approximately 1.0 million kVA, 1,901 structure miles of overhead lines, 162 miles of underground conduit and 651 miles of underground conductors in Arkansas.

The Company owns approximately 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73101. In addition to its executive offices, the Company owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, district offices, fleet and equipment service facilities, operation support and other properties.

During the three years ended December 31, 2008, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $1.6 billion and gross retirements were approximately $180.0 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. The additions during this three-year period amounted to approximately 26.3 percent of total property, plant and equipment at December 31, 2008.

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 Financial Statements. Except as set forth below and in Notes 13 and 14 of Notes to 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 financial position, results of operations or cash flows.

1. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the underreporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In qui tam actions, the Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.

The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming.

filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that the Company and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and the Company, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, the Company filed a notice of its intent to file a separate response brief, which the Company filed on January 11, 2008. Oral arguments were made to the Tenth Circuit on September 25, 2008. No ruling was made on the oral arguments and the court took the case under advisement. 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.

2. Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of OGE Energy’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of OGE Energy filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.

OGE Energy intends to vigorously defend this action. At this time, OGE Energy 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 OGE Energy.

3. Franchise Fee Lawsuit. On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes the Company to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on

December 4, 2008. The OCC expects to hear arguments for a motion to dismiss on March 26, 2009. The Company believes that this case is without merit.

4. Oxley Litigation. The Company has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma. This case has been pending for more than 11 years. The plaintiffs’ alleged that the Company breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs’ in amounts set forth in the contracts. The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, the Company agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, the Company will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The Company expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, the Company believes that this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations.

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

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by this item has been omitted.

Executive Officers of the Registrant.

The following persons were Executive Officers of the Registrant as of February 13, 2009:

Name	Age	Title

Peter B. Delaney	55	Chairman of the Board, President and Chief Executive Officer

Danny P. Harris	53	Senior Vice President and Chief Operating Officer

Scott Forbes	51	Controller, Chief Accounting Officer and Interim Chief Financial
		Officer

Carla D. Brockman	49	Vice President - Administration / Corporate Secretary

Robert E. Grasty	40	Vice President - Human Resources

Gary D. Huneryager	58	Vice President - Internal Audits

S. Craig Johnston	48	Vice President - Strategic Planning and Marketing

Jesse B. Langston	46	Vice President - Utility Commercial Operations

Jean C. Leger, Jr.	50	Vice President - Utility Operations

Cristina F. McQuistion	44	Vice President - Process and Performance Improvement

Howard W. Motley	60	Vice President - Regulatory Affairs

Reid V. Nuttall	51	Vice President - Enterprise Information and Performance

Melvin H. Perkins, Jr.	60	Vice President - Power Delivery

Paul L. Renfrow	52	Vice President - Public Affairs

John Wendling, Jr.	52	Vice President - Power Supply

Max J. Myers	34	Treasurer and Managing Director of Corporate Development
		and Finance

Jerry A. Peace	46	Chief Risk Officer

John D. Rhea	40	Assistant Corporate Secretary and Corporate Compliance Officer

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Harris, Forbes, Grasty, Huneryager, Johnston, Nuttall, Renfrow, Myers, Peace and Rhea and Ms. Brockman and Ms. McQuistion are also officers of OGE Energy. Each officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders of OGE Energy, currently scheduled for May 21, 2009.

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

Name	Business Experience

Peter B. Delaney	2007 – Present:	Chairman of the Board, President and Chief Executive Officer
		of OGE Energy and the Company
	2004 – Present:	Chief Executive Officer of Enogex LLC
	2007:	President and Chief Operating Officer of OGE Energy and the
		Company
	2004 – 2007:	Executive Vice President and Chief Operating Officer of
		OGE Energy and the Company
	2004:	Executive Vice President, Finance and Strategic Planning of
		OGE Energy and Chief Executive Officer of Enogex Inc.
	2004 – 2005:	President of Enogex Inc.

Danny P. Harris	2007 – Present:	Senior Vice President and Chief Operating Officer of OGE Energy
		and the Company and President of Enogex LLC
	2005 – 2007:	Senior Vice President of OGE Energy and President and
		Chief Operating Officer of Enogex Inc.
	2004 – 2005:	Vice President and Chief Operating Officer of Enogex Inc.

Scott Forbes	2008 – Present:	Interim Chief Financial Officer of OGE Energy and the Company
	2005 – Present:	Controller and Chief Accounting Officer of OGE Energy and
		the Company
	2004 – 2005:	Chief Financial Officer of First Choice Power (retail electric
		provider)
	2004 – 2005:	Senior Vice President and Chief Financial Officer of Texas
		New Mexico Power Company (electric utility)

Carla D. Brockman	2005 – Present:	Vice President – Administration / Corporate Secretary of
		OGE Energy and the Company
	2004 – 2005:	Corporate Secretary of OGE Energy and the Company

Robert E. Grasty	2008 – Present:	Vice President – Human Resources of OGE Energy and
		the Company
	2004 – 2008:	Vice President – Human Resources of TIAA-CREF (financial
		service company)
	2004:	Global Director – Human Resources of Pfizer
		(pharmaceuticals company)

Gary D. Huneryager	2005 – Present:	Vice President – Internal Audits of OGE Energy and the
		Company
	2004 – 2005:	Internal Audit Officer of OGE Energy and the Company

S. Craig Johnston	2007 – Present:	Vice President – Strategic Planning and Marketing of OGE Energy
		and the Company
	2004 – 2007:	Senior Vice President – Worldwide Oil & Gas Markets – Air
		Liquide (industrial gases company)
	2004:	Manager – Strategy & Business Optimization of ConocoPhillips
		(international oil company)

Jesse B. Langston	2006 – Present:	Vice President – Utility Commercial Operations of the Company
	2005 – 2006:	Director – Utility Commercial Operations of the Company
	2004 – 2005:	Director – Corporate Planning of the Company

Jean C. Leger, Jr.	2008 – Present:	Vice President – Utility Operations of the Company
	2004 – 2008:	Vice President of Operations of Enogex LLC
	2004 – 2005:	Director of Field Operations of Enogex Inc.

Name		Business Experience

Cristina F. McQuistion	2008 – Present:		Vice President – Process and Performance Improvement of
			OGE Energy and the Company
	2007 – 2008:		Executive Vice President and General Manager Point of Sale
			Systems of Teleflora
	2004 – 2007:		Executive Vice President – Member Services of Teleflora
			(floral industry and software services to floral industry company)

Howard W. Motley	2006 – Present:		Vice President – Regulatory Affairs of the Company
	2004 – 2006:		Director – Regulatory Affairs and Strategy of the Company
	2004:		Director – Regulatory Strategies and Utility Resources of the
			Company

Reid V. Nuttall	2006 – Present:	Vice President – Enterprise Information and Performance of
		OGE Energy and the Company
	2005 – 2006:	Vice President – Enterprise Architecture of National Oilwell
		Varco (oil and gas equipment company)
	2004 – 2005:	Chief Information Officer, Vice President – Information
		Technology of Varco International (oil and gas equipment
		company)

Melvin H. Perkins, Jr.	2007 – Present:	Vice President – Power Delivery of the Company
	2004 – 2007:	Vice President – Transmission of the Company

Paul L. Renfrow	2005 – Present:	Vice President – Public Affairs of OGE Energy and the Company
	2004 – 2005:	Director – Public Affairs of OGE Energy and the Company

John Wendling, Jr.	2007 – Present:	Vice President – Power Supply of the Company
	2005 – 2007:	Director, Power Plant Operations of the Company
	2004 – 2005:	Plant Manager, Sooner Power Plant of the Company
	2004:	Plant Manager, Horseshoe Lake/Mustang Power Plants of the
		Company

Max J. Myers	2009 – Present:	Treasurer and Managing Director of Corporate Development
		and Finance of OGE Energy and the Company
	2008:	Managing Director of Corporate Development and Finance of OGE
		Energy and the Company
	2005 – 2008:	Manager of Corporate Development of OGE Energy and the
		Company
	2004 – 2005:	Director of Corporate Finance and Development of Westar Energy,
		Inc. (electric utility)

Jerry A. Peace	2008 – Present:	Chief Risk Officer of OGE Energy and the Company
	2004 – 2008:	Chief Risk Officer and Compliance Officer of OGE Energy
		and the Company
	2004:	Chief Risk Officer of OGE Energy and the Company

John D. Rhea	2007 – Present:	Assistant Corporate Secretary and Corporate Compliance Officer
		of OGE Energy and the Company
	2006 – 2007:	Assistant General Counsel and Director of Corporate Compliance
		of El Paso Electric Company
	2005 – 2006:	Assistant General Counsel and Director of Corporate Compliance
		and Risk Management of El Paso Electric Company
	2004 – 2005:	Assistant General Counsel and Director of Corporate Compliance
		of El Paso Electric Company (electric utility)

PART II

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

Currently, all of the Company’s outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for the Company’s common stock.

During 2008, 2007 and 2006, the Company declared dividends of approximately $35.0 million, $56.0 million and $24.0 million, respectively, to OGE Energy.

Item 6. Selected Financial Data.

HISTORICAL DATA

Year ended December 31	2008	2007	2006 (A)	2005	2004
SELECTED FINANCIAL DATA
(In millions)
Results of Operations Data:
Operating revenues	$ 1,959.5	$ 1,835.1	$ 1,745.7	$ 1,720.7	$ 1,578.1
Cost of goods sold	1,114.9	1,025.1	950.0	994.2	914.2
Gross margin on revenues	844.6	810.0	795.7	726.5	663.9
Other operating expenses	566.3	518.0	501.8	494.3	471.6
Operating income	278.3	292.0	293.9	232.2	192.3
Interest income	4.4	---	1.9	2.6	2.7
Allowance for equity funds used during construction	---	---	4.1	---	0.9
Other income (loss)	3.6	5.0	4.0	(2.8)	4.5
Other expense	11.8	7.2	9.7	2.5	2.3
Interest expense	79.1	54.9	60.1	47.2	37.5
Income tax expense	52.4	73.2	84.8	52.6	53.0
Net income	$ 143.0	$ 161.7	$ 149.3	$ 129.7	$ 107.6

Balance Sheet Data (at period end):
Property, plant and equipment, net	$ 3,955.5	$ 3,233.6	$ 2,979.1	$ 2,670.2	$ 2,548.6
Total assets	$ 4,851.2	$ 3,874.9	$ 3,589.7	$ 3,255.0	$ 3,057.7
Long-term debt	$ 1,541.4	$ 843.4	$ 843.3	$ 844.0	$ 847.2
Total stockholder’s equity	$ 1,824.3	$ 1,423.3	$ 1,322.0	$ 1,116.0	$ 1,062.3

CAPITALIZATION RATIOS (B)
Stockholder’s equity	54.2%	62.8%	61.1%	56.9%	55.6%
Long-term debt	45.8%	37.2%	38.9%	43.1%	44.4%

RATIO OF EARNINGS TO
FIXED CHARGES (C)
Ratio of earnings to fixed charges	3.25	4.78	4.43	4.44	4.76

(A) The Company adopted SFAS No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method, effective January 1, 2006, which required the Company to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award.

(B) Capitalization ratios = [Stockholder’s equity / (Stockholder’s equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Stockholder’s equity + Long-term debt + Long-term debt due within one year)].

(C) For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction; and (2) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.

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

Introduction

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company’s operations are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”) which 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 was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

Executive Overview

Strategy

•

The Company purchased a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired, combined-cycle NRG McClain Station in July 2004;

•

The Company purchased a 51 percent interest in the 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (the “Redbud Facility”) in September 2008;

•

initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure.

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

Summary of Operating Results

2008 compared to 2007. The Company reported net income of approximately $143.0 million and $161.7 million, respectively, during 2008 and 2007, a decrease of approximately $18.7 million or 11.6 percent, primarily due to higher operation and maintenance expense, higher depreciation and amortization expense, higher other expense and higher interest expense partially offset by a higher gross margin on revenues (“gross margin”) due to increased rates from various regulatory riders implemented during 2008 and lower income tax expense.

2007 compared to 2006. The Company reported net income of approximately $161.7 million and $149.3 million, respectively, during 2007 and 2006, an increase of approximately $12.4 million, or 8.3 percent. The increase was primarily due to a higher gross margin from higher rates from the Centennial wind farm rider, security rider and Arkansas rate case, increased peak demand and related revenues by non-residential customers in the Company’s service territory and new customer growth in the Company’s service territory partially offset by cooler weather in the Company’s service territory. Also contributing to the increase in net income was lower interest expense and lower income tax expense partially offset by higher depreciation and amortization expense.

Recent Developments and Regulatory Matters

Changes in Capital and Credit Markets

As a result of recent volatile conditions in global capital markets, including the bankruptcy filing of Lehman Brothers Holdings, Inc. (“Lehman”), general liquidity in short-term credit markets has been constrained despite several pro-active intervention measures undertaken by the Federal Reserve, the Department of the Treasury, the United States Congress and the President of the United States. As explained in more detail below, the Company historically has maintained access to short-term liquidity through the A2/P2 commercial paper market and utilization of direct borrowings on certain committed credit agreements, although the ability to access the commercial paper market has been more limited in recent months.

The recent volatility in global capital markets has lead to a reduction in the current value of long-term investments held in OGE Energy’s pension trust and post-retirement benefit plan trusts. The recent decline in asset value for the plans, if it continues for any length of time, could require additional future funding requirements.

On September 15, 2008, Lehman filed for bankruptcy protection and has not funded their portion of OGE Energy’s and the Company’s revolving credit agreements. At December 31, 2008, approximately $4 million and $11 million, respectively, of OGE Energy’s and the Company’s revolving credit agreements are not available as this portion was assigned to Lehman.

Acquisition of Redbud Power Plant

On September 29, 2008, the Company acquired a 51 percent interest in the Redbud Facility for approximately $434.5 million. The Company will jointly own the Redbud Facility with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”), and the Company will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Each of the joint owners will be entitled to its respective portion of the output and will pay its pro rata share of all costs of operating and maintaining the Redbud Facility. The Company implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes. For additional information regarding the acquisition of the Redbud Facility, see Note 14 of Notes to Financial Statements.

Cancelled Red Rock Power Plant and Storm Cost Recovery Rider

On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. On June 27, 2008, the Company filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs ($35.9 million at December 31, 2007) and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, the Company will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with the Company’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date the Company begins to recover the regulatory asset through the base rates established in the Company’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in the Company’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover the Company’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess sulfur dioxide (“SO2”) allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by the Company and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, the Company wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Financial Statements.

Arkansas Rate Case Filing

On August 29, 2008, the Company filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that the Company can reliably meet growing customer demand for electricity, and a return on equity of 12.25 percent. In January 2009, the APSC Staff recommended a $12.0 million rate increase based on a 10.5 percent return on equity. The Attorney General’s consultant recommended a return on equity at the current authorized level of 10.0 percent and stated that his analysis identified at least $10.9 million in reductions to the Company’s rate increase request. A hearing is scheduled for April 7, 2009. An order from the APSC is expected in June 2009 with new rates targeted for implementation in July 2009.

2009 Oklahoma Rate Case Filing

Beginning in October 2008, the Company began developing a rate case filing for the Oklahoma jurisdiction. On January 20, 2009, the Company notified the OCC that it will make its planned Oklahoma rate case filing on or about February 26, 2009. The Company is finalizing the preparation of the rate case and expects to request an increase of between $100 million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest.

Proposed Wind Power Project

2009 Outlook

OGE Energy’s 2009 earnings guidance includes $177 million to $191 million of net income for the Company.

Key factors and assumptions for 2009 include:

•

Normal weather patterns are experienced for the year;

•

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

•

A reasonable regulatory outcome in the Oklahoma rate case with new rates in effect before the end of the third quarter of 2009;

•

Arkansas annual rate increase of approximately $12 million to $14 million implemented in mid-2009;

•

Storm cost recovery rider of approximately $8 million to $10 million;

•

Operating expenses of approximately $595 million to $610 million;

•

Interest expense of approximately $95 million to $98 million; and

•

An effective tax rate of approximately 30 percent.

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

Results of Operations

The following discussion and analysis presents factors that affected the Company’s results of operations for the years ended December 31, 2008, 2007 and 2006 and the Company’s financial position at December 31, 2008 and 2007. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

Year ended December 31 (In millions)	2008		2007		2006
Operating income	$	278.3	$	292.0	$	293.9
Net income	$	143.0	$	161.7	$	149.3

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

Year ended December 31 (Dollars in millions)	2008	2007	2006
Operating revenues	$ 1,959.5	$ 1,835.1	$ 1,745.7
Cost of goods sold	1,114.9	1,025.1	950.0
Gross margin on revenues	844.6	810.0	795.7
Other operation and maintenance	351.6	320.7	316.5
Depreciation and amortization	155.0	141.3	132.2
Taxes other than income	59.7	56.0	53.1
Operating income	278.3	292.0	293.9
Interest income	4.4	---	1.9
Allowance for equity funds used during construction	---	---	4.1
Other income	3.6	5.0	4.0
Other expense	11.8	7.2	9.7
Interest expense	79.1	54.9	60.1
Income tax expense	52.4	73.2	84.8
Net income	$ 143.0	$ 161.7	$ 149.3
Operating revenues by classification
Residential	$ 751.2	$ 706.4	$ 698.8
Commercial	479.0	450.1	428.3
Industrial	219.8	221.4	215.7
Oilfield	151.9	140.9	129.3
Public authorities and street light	190.3	181.4	171.0
Sales for resale	64.9	68.8	65.4
Provision for rate refund	(0.4)	0.1	(0.9)
System sales revenues	1,856.7	1,769.1	1,707.6
Off-system sales revenues	68.9	35.1	2.7
Other	33.9	30.9	35.4
Total operating revenues	$ 1,959.5	$ 1,835.1	$ 1,745.7
MWH (A) sales by classification (in millions)
Residential	9.0	8.7	8.7
Commercial	6.5	6.3	6.2
Industrial	4.0	4.2	4.4
Oilfield	2.9	2.8	2.7
Public authorities and street light	3.0	3.0	2.9
Sales for resale	1.4	1.4	1.5
System sales	26.8	26.4	26.4
Off-system sales	1.4	0.7	---
Total sales	28.2	27.1	26.4
Number of customers	770,088	762,234	754,840
Average cost of energy per KWH (B) - cents
Natural gas	8.455	6.872	6.829
Coal	1.153	1.143	1.114
Total fuel	3.337	3.173	3.003
Total fuel and purchased power	3.710	3.523	3.366
Degree days (C)
Heating - Actual	3,394	3,175	2,746
Heating - Normal	3,650	3,631	3,631
Cooling - Actual	2,081	2,221	2,485
Cooling - Normal	1,912	1,911	1,911

(A) Megawatt-hour.

(B) Kilowatt-hour.

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

2008 compared to 2007. The Company’s operating income decreased approximately $13.7 million in 2008 as compared to 2007 primarily due to higher operating expenses, higher depreciation and amortization expense and higher taxes other than income partially offset by a higher gross margin.

Gross Margin

Gross margin was approximately $844.6 million in 2008, as compared to approximately $810.0 million in 2007, an increase of approximately $34.6 million, or 4.3 percent. The gross margin increased primarily due to:

•

new revenues from the Redbud Facility rider and the storm cost recovery rider, which increased the gross margin by approximately $21.1 million;

•

new customer growth in the Company’s service territory, which increased the gross margin by approximately $8.4 million; and

•

increased demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by approximately $5.0 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $857.2 million in 2008 as compared to approximately $756.1 million in 2007, an increase of approximately $101.1 million, or 13.4 percent, primarily due to higher natural gas prices. The Company’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. In 2008, the Company’s fuel mix was 68 percent coal, 30 percent natural gas and two percent wind. In 2007, the Company’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. Purchased power costs were approximately $257.0 million in 2008 as compared to approximately $268.6 million in 2007, a decrease of approximately $11.6 million, or 4.3 percent. This decrease was primarily due to lower purchases from the energy imbalance service market partially offset by capacity payments made to Redbud due to the purchase power agreement in effect prior to the Company’s purchase of the Redbud Facility.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex.

Operating Expenses

Other operation and maintenance expenses were approximately $351.6 million in 2008 as compared to approximately $320.7 million in 2007, an increase of approximately $30.9 million, or 9.6 percent. The increase in other operation and maintenance expenses was primarily due to:

•

an increase of approximately $9.5 million due to a correction of the over-capitalization of certain payroll, benefits, other employee related costs and overhead costs in previous years, as discussed in Note 2 of Notes to Financial Statements;

•

a decrease in capitalized work of approximately $14.0 million primarily related to costs related to the 2007 ice storm that were deferred as a regulatory asset;

•

an increase of approximately $6.9 million in salaries and wages expense primarily due to hiring additional employees to support the Company’s operations as well as salary increases in 2008;

•

an increase of approximately $6.6 million in contract services and approximately $1.5 million in materials and supplies primarily attributable to overhaul expenses at several of the Company’s power plants;

•

an increase of approximately $5.3 million due to increased spending on vegetation management;

•

an increase of approximately $2.2 million in fleet transportation charges primarily due to higher fuel and maintenance costs; and

•

an increase of approximately $1.3 million in professional services expense primarily due to higher engineering consulting services during 2008 as compared to 2007.

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

•

lower allocations from OGE Energy of approximately $9.0 million due to lower pension and medical costs and lower incentive compensation accruals;

•

a decrease of approximately $4.0 million primarily due to overtime worked during the 2007 ice storm; and

•

a decrease of approximately $3.0 million due to a lower bad debt expense.

Depreciation and amortization expense was approximately $155.0 million in 2008 as compared to approximately $141.3 million in 2007, an increase of approximately $13.7 million or 9.7 percent. The increase was primarily due to additional assets, including the Redbud Facility, being placed into service in 2008 and amortization of the Arkansas storm costs that are currently recorded as a regulatory asset (see Note 1 of Notes to the Financial Statements).

Taxes other than income were approximately $59.7 million in 2008 as compared to approximately $56.0 million in 2007, an increase of approximately $3.7 million, or 6.6 percent, primarily due to higher ad valorem and payroll taxes.

Additional Information

Interest Income. Interest income was approximately $4.4 million in 2008. There was less than $0.1 million of interest income in 2007. The increase in interest income was primarily due to interest from customers related to the fuel under recovery balance during 2008 and interest income from short-term investments.

Other Income. Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $3.6 million in 2008 as compared to approximately $5.0 million in 2007, a decrease of approximately $1.4 million, or 28 percent, primarily due to a lower gain on the guaranteed flat bill tariff due to warmer than normal weather with more customers participating in this plan.

Other Expense. Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $11.8 million in 2008 as compared to approximately $7.2 million in 2007, an increase of approximately $4.6 million or 63.9 percent. The increase in other expense was primarily due to:

•

a write-down of deferred costs associated with the Red Rock power plant of approximately $7.5 million; and

•

a write-down of approximately $1.5 million associated with the 2007 and 2006 storm costs related to a settlement with the OCC. See Note 14 of Notes to Financial Statements for a discussion of these matters.

These increases in other expense were partially offset by a write-off of approximately $3.1 million associated with the Red Rock power plant for the Arkansas and the FERC jurisdictions during 2007.

Interest Expense. Interest expense was approximately $79.1 million in 2008 as compared to approximately $54.9 million in 2007, an increase of approximately $24.2 million, or 44.1 percent. The increase in interest expense was primarily due to:

•

an increase of approximately $16.4 million in interest expense related to the issuances of long-term debt in January, September and December 2008;

•

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

•

an increase of approximately $2.9 million in interest expense related to interest on short-term debt primarily due to increased commercial paper borrowings and revolving credit borrowings to fund the purchase of the Redbud Facility and daily operational needs of the Company.

These increases in interest expense were partially offset by a decrease of approximately $3.1 million in interest expense associated with the interest due to customers related to the fuel over recovery balance in 2007.

Income Tax Expense. Income tax expense was approximately $52.4 million in 2008 as compared to approximately $73.2 million in 2007, a decrease of approximately $20.8 million, or 28.4 percent, primarily due to lower pre-tax income during 2008 as compared to 2007 as well as a lower overall effective income tax rate primarily due to an increase in Federal renewable energy credits and additional state income tax credits in 2008 as compared 2007.

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

Gross Margin

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

•

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

•

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

•

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

These increases in the gross margin were partially offset by:

•

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

•

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

Fuel expense was approximately $756.1 million in 2007 as compared to approximately $730.3 million in 2006, an increase of approximately $25.8 million, or 3.5 percent, primarily due to increased natural gas generation in 2007 and a gain recognized from the sale of SO2 allowances of approximately $8.9 million in 2006. The Company’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. In 2007, the Company’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. In 2006, the Company’s fuel mix was 67 percent coal and 33 percent natural gas. Purchased power costs were approximately $268.6 million in 2007 as compared to approximately $219.7 million in 2006, an increase of approximately $48.9 million, or 22.3 percent. This increase was primarily due to the Company’s entrance into the energy imbalance service market on February 1, 2007 (see Note 1 of Notes to Financial Statements for a further discussion).

Operating Expenses

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

•

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

•

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

•

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

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

•

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

•

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

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

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

Additional Information

Interest Income. There was less than $0.1 million of interest income in 2007. Interest income was approximately $1.9 million in 2006. The decrease was primarily due to interest income earned on fuel under recoveries in 2006 while there was a fuel over recovery balance in 2007.

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

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

Other Expense. Other expense was approximately $7.2 million in 2007 as compared to approximately $9.7 million in 2006, a decrease of approximately $2.5 million, or 25.8 percent, primarily due to a loss on the retirement of fixed assets of approximately $5.2 million in 2006 partially offset by the write-off of non-recoverable Red Rock expenses of approximately $3.1 million for Arkansas and the FERC jurisdictions in 2007.

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

•

a settlement with the IRS resulting in a reversal of interest expense of approximately $7.2 million in 2007; and

•

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

These decreases in interest expense were partially offset by:

•

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

•

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

•

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

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

Financial Condition

The balance of Cash and Cash Equivalents was approximately $50.7 million at December 31, 2008 with no balance at December 31, 2007. The increase was primarily due to the need for the Company to have adequate liquidity due to the volatility of the commercial paper and capital markets.

The balance of Accounts Receivable was approximately $172.2 million and $134.9 million at December 31, 2008 and 2007, respectively, an increase of approximately $37.3 million, or 27.7 percent, primarily due to an increase in the Company’s billings to its customers and increased rates from the Redbud Facility rider and storm cost recovery rider.

The balance of Property, Plant and Equipment In Service was approximately $6.1 billion and $5.4 billion at December 31, 2008 and 2007, respectively, an increase of approximately $0.7 billion, or 13.0 percent, primarily due the purchase of the Redbud Facility as well as other projects for transmission and distribution.

The balance of Construction Work in Process was approximately $169.1 million and $112.4 million at December 31, 2008 and 2007, respectively, an increase of approximately $56.7 million, or 50.4 percent, primarily due to costs associated with the OU Spirit wind project in western Oklahoma.

The balance of Regulatory Asset – SFAS No. 158 was approximately $344.7 million and $174.6 million at December 31, 2008 and 2007, respectively, an increase of approximately $170.1 million, or 97.4 percent. The increase was primarily due to an increase in the pension plan, restoration of retirement income plan and postretirement benefit plan obligations due to a decrease in the fair value of plan assets in 2008.

The balance of Other Deferred Charges was approximately $56.0 million and $76.9 million at December 31, 2008 and 2007, respectively, a decrease of approximately $20.9 million, or 27.2 percent, primarily due to write-downs of the deferred costs associated with the cancellation of the Red Rock power plant project and 2007 ice storm costs and amortization of the regulatory asset for deferred pension costs.

The balance of Accounts Payable – Other was approximately $105.0 million and $164.3 million at December 31, 2008 and 2007, respectively, a decrease of approximately $59.3 million, or 36.1 percent, primarily due timing of outstanding checks clearing the bank, payments made in the first quarter of 2008 for the December 2007 ice storm and a decrease in the payable for gas purchases.

The balance of Advances from Parent was approximately $17.6 million and $348.0 million at December 31, 2008 and 2007, respectively, a decrease of approximately $330.4 million, or 94.9 percent, primarily due to the repayment of outstanding advances primarily due to the issuance of long-term debt in January, September and December 2008.

The balance of Long-Term Debt was approximately $1.5 billion and $0.8 billion at December 31, 2008 and 2007, respectively, an increase of approximately $0.7 billion, or 87.5 percent, primarily due to the issuance of long-term debt in the January, September and December 2008.

The balance of Accrued Benefit Obligations was approximately $261.9 million and $118.1 million at December 31, 2008 and 2007, respectively, an increase of approximately $143.8 million, primarily due to plan changes for prior service cost and net loss for the pension plan, restoration of retirement income plan and postretirement benefit plan partially offset by pension plan contributions in 2008.

The balance of Accumulated Deferred Income Taxes was approximately $722.8 million and $633.0 million at December 31, 2008 and 2007, respectively, an increase of approximately $89.8 million, or 14.2 percent, primarily due to accelerated bonus tax depreciation which resulted in higher Federal and state deferred tax accruals.

The balance of Common Stockholder’s Equity was approximately $958.4 million and $665.4 million at December 31, 2008 and 2007, respectively, an increase of approximately $293.0 million, or 44.0 percent, due to a capital contribution from OGE Energy to the Company in September 2008 to fund a portion of the purchase of the Redbud Facility.

Off-Balance Sheet Arrangements

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

Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with, the Company. The Company has the following material off-balance sheet arrangements.

Railcar Lease Agreement

At December 31, 2007, the Company had a noncancellable operating lease with purchase options, covering 1,409 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation units. In April 2008, the Company amended its contract to add 55 new railcars for approximately $3.5 million. At the end of the new lease term, which is January 31, 2011, the Company has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If the Company chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, the Company would be responsible for the difference in those values up to a maximum of approximately $31.5 million. See Note 13 of Notes to Financial Statements for a further discussion.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities in its electric utility business. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. However, OGE Energy’s and the Company’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis. However, in late 2008, OGE Energy’s and the Company’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, the Company repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. The Company intends to utilize commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreement and begin utilizing the commercial paper market when available.

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

			Less than
			1 year		1 - 3 years		3 - 5 years		More than
(In millions)	Total		(2009)		(2010-2011)		(2012-2013)		5 years
Capital expenditures including AFUDC (A)	$	2,736.5	$	611.5	$	865.8	$	825.5	$	433.7
Maturities of long-term debt		1,545.3		---		---		---		1,545.3
Interest payments on long-term debt		1,636.0		98.4		196.9		196.9		1,143.8
Pension funding obligations		143.0		47.0		48.0		48.0		N/A
Total capital requirements		6,060.8		756.9		1,110.7		1,070.4		3,122.8

Operating lease obligations
Railcars		45.7		3.9		41.8		---		---

Other purchase obligations and commitments
Cogeneration capacity payments		416.9		86.8		168.1		162.0		N/A
Fuel minimum purchase commitments		527.3		320.7		179.3		7.8		19.5
Total other purchase obligations and
commitments		944.2		407.5		347.4		169.8		19.5

Total capital requirements, operating lease obligations
and other purchase obligations and commitments		7,050.7		1,168.3		1,499.9		1,240.2		3,142.3
Amounts recoverable through fuel
adjustment clause (B)		(989.9)		(411.4)		(389.2)		(169.8)		(19.5)
Total, net	$	6,060.8	$	756.9	$	1,110.7	$	1,070.4	$	3,122.8

(A) Under current environmental laws and regulations, the Company may be required to spend approximately $110 million in capital expenditures on its power plants related to regional haze projects. Until the compliance plan is approved as discussed below, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty.

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

N/A – not available

Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for the Company’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional fuel purchase obligations of the Company noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC.

2008 Capital Requirements and Financing Activities

Total capital requirements, consisting of capital expenditures, maturities of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $991.2 million in 2008. There were no contractual obligations, net of recoveries through fuel adjustment clauses in 2008. Approximately $4.0 million of the 2008 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $453.7 million in 2007. There were no contractual obligations, net of recoveries through fuel adjustment clauses in 2007. Approximately $7.3 million of the 2007 capital requirements were to comply with environmental regulations. During 2008, the Company’s sources of capital were internally generated funds from operating cash flows and long-term borrowings. Changes in working capital reflect the seasonal nature of the Company’s business, the revenue lag between billing and collection from customers and fuel inventories. See “Financial Condition” for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

Issuance of Long-Term Debt

In January 2008, the Company issued $200 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings.

In September 2008, the Company issued $250 million of 6.35% senior notes due September 1, 2018. The proceeds from the issuance were used to fund a portion of the acquisition of the Redbud Facility. Pending such use, the proceeds were used to temporarily repay a portion of the Company’s outstanding commercial paper borrowings, as well as short-term borrowings from OGE Energy, both of which were incurred in part to fund the Company’s daily operational needs.

In December 2008, the Company issued $250 million of 8.25% senior notes due January 15, 2019. The proceeds from the issuance were used to repay borrowings under the Company’s term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC, as discussed in Note 11 of Notes to Financial Statements, and OGE Energy’s and the Company’s revolving credit agreements, which were used to fund the Company’s daily operational needs as well as the Company’s acquisition of the Redbud Facility.

Long-Term Debt Maturities

There are no maturities of the Company’s long-term debt during the next five years.

At December 31, 2008, the Company had approximately $50.7 million of cash on hand. At December 31, 2008, the Company had approximately $388.7 million of net available liquidity under its revolving credit agreement.

Cash Flows

Year Ended December 31(In millions)	2008		2007		2006
Net cash provided from operating activities	$	206.4	$	230.1	$	455.1
Net cash used in investing activities		(839.6)		(376.4)		(410.1)
Net cash provided from (used in) financing activities		683.9		146.3		(45.0)

The reduction of approximately $23.7 million in net cash provided from operating activities in 2008 as compared to 2007 was primarily due to: (i) a decrease in accounts payable due to payments in the first quarter of 2008 related to the December 2007 ice storm, (ii) an increase in fuel clause recoveries due to higher fuel recoveries in 2008 as compared to 2007, (iii) a decrease in income taxes payable due to the settlement of prior year liabilities resulting from filing of tax returns and payments related to IRS audit settlements and (iv) a decrease in accounts receivable due to higher billed sales in 2008. The reduction of approximately $225.0 million in net cash provided from operating activities in 2007 as compared to 2006 was primarily related to lower fuel recoveries from Company customers partially offset by changes to other working capital.

The increase of approximately $463.2 million in net cash used in investing activities in 2008 as compared to 2007 primarily related to a higher level of capital expenditures primarily related to the purchase of the Redbud Facility. The decrease in net cash used in investing activities of approximately $33.7 million in 2007 as compared to 2006 related to lower levels of capital expenditures.

The increase of approximately $537.6 million in net cash provided from financing activities in 2008 as compared to 2007 primarily related to proceeds received from the issuance of long-term debt in January, September and December 2008 and an increase in capital contribution from the parent to fund a portion of the purchase of the Redbud Facility partially offset by a decrease in short-term debt primarily due to proceeds received from the issuance of long-term debt used to repay short-term borrowings. The increase in net cash provided from financing activities of approximately $191.3 million in 2007 as compared to 2006 primarily related to higher levels of short-term debt partially offset by reduced amounts related to the issuance of long-term debt.

Future Capital Requirements

Capital Expenditures

The Company’s current 2009 to 2014 construction program includes continued investment in its distribution, generation and transmission system. The Company’s current estimates of capital expenditures are approximately: 2009 - $611.5 million, 2010 - $405.9 million, 2011 - $459.9 million, 2012 - $405.9 million, 2013 - $419.6 million and 2014 - $433.7 million. These capital expenditures include expenditures related to (i) the proposed transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma, (ii) the Company’s proposed 101 MW OU Spirit wind power project in western Oklahoma, (iii) the Company’s proposed system hardening plan and (iv) the Company’s transmission/substation SPP project (see Note 14 of Notes to Financial Statements for a further discussion). These capital expenditures exclude expenditures associated with Best Available Retrofit Technology (“BART”) requirements. As discussed in Note 13 of Notes to Financial Statements, due to comments from the U.S. Environmental Protection Agency (“EPA”) that the Company’s proposed initial BART compliance plan would not satisfy the applicable requirements, the Company completed additional analysis. On May 30, 2008, the Company filed the results with the Oklahoma Department of Environmental Quality (“ODEQ”) for the affected generating units. In the May 30, 2008 filing, the Company indicated its intention to install low nitrogen oxide (“NOX”) combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. The Company believes that these control measures will achieve visibility improvements in a cost-effective manner. The Company did not propose the installation of scrubbers at its four coal-fired generating units because the Company concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. The Company previously reported an expectation that a compliance plan would be approved by the EPA by December 31, 2008; however, submission of the overall compliance plan by the ODEQ (which will include the Company’s compliance plan previously submitted to the ODEQ) has been delayed and the current timing of the EPA approval cannot be reasonably predicted. In a letter dated November 4, 2008, the EPA notified the ODEQ that they had completed their review of BART applications for all affected sources in Oklahoma, which included the Company. The EPA did not approve or disapprove the applications, however, additional information was requested from the ODEQ by the EPA regarding the Company’s plan. The Company cannot predict what action the EPA or the ODEQ will take in response to its May 30, 2008 filing or the November 4, 2008 letter from the EPA. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. Due to this uncertainty regarding BART costs, the Company has excluded any BART costs from the foregoing capital expenditure estimates. The Company also has approximately 440 MWs of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. The Company will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

Pension and Postretirement Benefit Plans

All eligible employees of the Company are covered by a non-contributory defined benefit pension plan. During 2008, actual asset returns for OGE Energy’s defined benefit pension plan were negatively affected by the slowdown in growth in the equity markets. At December 31, 2008, approximately 45 percent of the pension plan assets were invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2008, asset returns on the pension plan decreased approximately 25.1 percent as compared to an increase of approximately 4.4 percent in 2007. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.

During both 2008 and 2007, OGE Energy made contributions to its pension plan of approximately $50.0 million. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. During 2009, OGE Energy may contribute up to $50.0 million to its pension plan, of which approximately $47.0 million is expected to be the Company’s portion.

In accordance with Statement of Financial Accounting Standard (“SFAS”) No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization

from the responsibility for the pension benefit obligation or the retirement restoration obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007, OGE Energy and the Company experienced an increase in both the number of employees electing to retire and the amount of lump-sum payments to be paid to such employees upon retirement as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. The Company did not record a pension settlement charge during 2008. The pension settlement charge and retirement restoration plan settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions)	OGE Energy		Company’s Portion (A)

Pension Settlement Charge:
2007	$	16.7	$	13.3

Retirement Restoration Plan Settlement Charge:
2007	$	2.3	$	0.1

(A) The Company’s Oklahoma jurisdictional portion of these changes were recorded as a regulatory asset (see Note 1 of Notes to Financial Statements for a further discussion).

As discussed in Note 12 of Notes to Financial Statements, in 2000 OGE Energy made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired on or after February 1, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, OGE Energy’s cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, OGE Energy’s cash requirements should decrease and will be much less sensitive to changes in discount rates.

At December 31, 2008, the projected benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s pension plan and restoration of retirement income plan was approximately $433.7 million and $309.2 million, respectively, for an underfunded status of approximately $124.5 million. Also, at December 31, 2008, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $191.9 million and $55.1 million, respectively, for an underfunded status of approximately $136.8 million. The above amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1 of Notes to Financial Statements. The amount recorded as a regulatory asset represents a net periodic pension cost to be recognized in the Statements of Income in future periods.

At December 31, 2007, the projected benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s pension plan and restoration of retirement income plan was approximately $414.4 million and $400.7 million, respectively, for an underfunded status of approximately $13.7 million. Also, at December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $179.2 million and $76.0 million, respectively, for an underfunded status of approximately $103.2 million. The above amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1 of Notes to Financial Statements. The amount recorded as a regulatory asset represents a net periodic pension cost to be recognized in the Statements of Income in future periods.

Pension Plan Costs and Assumptions

Security Ratings

	Moody’s	Standard & Poor’s	Fitch’s
Company Senior Notes	A2	BBB+	AA-

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

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

Future Sources of Financing

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. At December 31, 2008 and 2007, the Company had no outstanding borrowings under its revolving credit agreement and no outstanding commercial paper borrowings. The following table shows OGE Energy’s and the Company’s revolving credit agreements and available cash at December 31, 2008.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate	Amount	Weighted-Average
Entity	Commitment	Outstanding	Interest Rate	Maturity
OGE Energy	$ 596.0	$ 298.0	0.75%	December 6, 2012
The Company	389.0	---	---%	December 6, 2012
	985.0	298.0	0.75%
Cash	50.7	N/A	N/A	N/A
Total	$ 1,035.7	$ 298.0	0.75%

OGE Energy’s and the Company’s ability to access the commercial paper market was adversely impacted by the market turmoil that began in September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis. However, in late 2008, OGE Energy’s and the Company’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, the Company repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. The Company intends to utilize commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreement and begin utilizing the commercial paper market when available. Also, the Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31,

2010. See Note 11 of Notes to Financial Statements for a discussion of OGE Energy’s and the Company’s short-term debt activity.

Capital Contribution from OGE Energy

On September 25, 2008, OGE Energy made a capital contribution to the Company of approximately $293.0 million.

Critical Accounting Policies and Estimates

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

Pension and Postretirement Benefit Plans

OGE Energy has defined benefit retirement and postretirement plans that cover substantially all of the Company’s employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 12 of Notes to Financial Statements. The assumed return on plan assets is based on management’s expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the pension plan. The following table indicates the sensitivity of the pension plan funded status to these variables.

			Impact on
	Change		Funded Status
Actual plan asset returns	+/-	5 percent	+/-	$19.5 million
Discount rate	+/-	0.25 percent	+/-	$16.7 million
Contributions	+	$10.0 million	+	$10.0 million
Expected long-term return on plan assets	+/-	1 percent		None

Commitments and Contingencies

Except as otherwise disclosed in this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a

material adverse effect on the Company’s financial position, results of operations or cash flows. See Notes 13 and 14 of Notes to Financial Statements and Item 3 in this Form 10-K.

Asset Retirement Obligations

In accordance with FIN No. 47, “Accounting for Conditional Asset Retirement Obligations,” an entity was required to recognize a liability for the fair value of an ARO that was conditional on a future event if the liability’s fair value could be reasonably estimated. The fair value of a liability for the conditional ARO was recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO was factored into the measurement of the liability when sufficient information existed. However, in some cases, there was insufficient information to estimate the fair value of an ARO. In these cases, the liability was initially recognized in the period in which sufficient information was available for an entity to make a reasonable estimate of the liability’s fair value. The Company did not recognize any new AROs during 2008; however, the Company has identified certain AROs that have not been recorded because the Company determined that these assets, primarily related to the Company’s power plant sites, have indefinite lives.

Hedging Policies

The Company engages in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2006 and 2007, the Company entered into treasury lock agreements relating to managing interest rate exposure on the debt portfolio or anticipated debt issuances to modify the interest rate exposure on fixed rate debt issues. The treasury lock agreements in 2006 and 2007 qualified as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The objective of these treasury lock agreements was to protect against the variability of future interest payments of long-term debt that was issued by the Company.

Regulatory Assets and Liabilities

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

The Company records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The Company adopted certain provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which required the Company to separately disclose the items that had not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. The Company met both criteria and, therefore, recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

Unbilled Revenues

The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 2008, if the estimated

usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of approximately $0.3 million. At December 31, 2008 and 2007, Accrued Unbilled Revenues were approximately $47.0 million and $45.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. At December 31, 2008, if the provision rate were to increase or decrease by ten percent, this would cause a change in the uncollectible expense recognized of approximately $0.2 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Balance Sheets and is included in Other Operation and Maintenance Expense on the Statements of Income. The allowance for uncollectible accounts receivable was approximately $2.3 million and $3.4 million at December 31, 2008 and 2007, respectively.

Accounting Pronouncements

See Notes 1, 2, 3, 4, 8 and 12 of Notes to Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

Electric Competition; Regulation

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

Commitments and Contingencies

Except as disclosed otherwise in this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. See Notes 13 and 14 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of the Company’s commitments and contingencies.

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

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

Risk Committee and Oversight

Management monitors market risks using a risk committee structure. OGE Energy’s Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement

of strategies and policies for all risk management activities of the Company. This committee’s emphasis is a holistic perspective of risk measurement and policies targeting the Company’s overall financial performance. The Risk Oversight Committee is authorized by, and reports quarterly to, the Audit Committee of the Board of Directors of OGE Energy.

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

Risk Policies

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

Interest Rate Risk

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

The Company entered into two separate treasury lock agreements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008 in conjunction with the issuance of long-term debt by the Company.

The fair value of the Company’s long-term debt is based on quoted market prices. At December 31, 2008, the Company had no outstanding interest rate swap agreements. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date. There are no maturities of the Company’s long-term debt during the next five years.

Year ended December 31	After				12/31/08
(Dollars in millions)	2013		Total		Fair Value
Fixed-rate debt (A)
Principal amount	$	1,410.0	$	1,410.0	$	1,327.4
Weighted-average
interest rate		6.63%		6.63%		---
Variable-rate debt (B)
Principal amount	$	135.3	$	135.3	$	135.3
Weighted-average
interest rate		2.41%		2.41%		---

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

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

Management may designate certain derivative instruments for the purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133. Normal purchases and normal sales contracts are not recorded in Price Risk Management assets or liabilities in the Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales to electric power contracts by the Company and for fuel procurement by the Company.

Credit Risk

Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.

New business customers are required to provide a security deposit in the form of cash, a bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Item 8. Financial Statements and Supplementary Data.

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF INCOME

Year ended December 31 (In millions)	2008		2007		2006

OPERATING REVENUES	$	1,959.5	$	1,835.1	$	1,745.7

COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)		1,114.9		1,025.1		950.0
Gross margin on revenues		844.6		810.0		795.7
Other operation and maintenance		351.6		320.7		316.5
Depreciation and amortization		155.0		141.3		132.2
Taxes other than income		59.7		56.0		53.1

OPERATING INCOME		278.3		292.0		293.9

OTHER INCOME (EXPENSE)
Interest income		4.4		---		1.9
Allowance for equity funds used during construction		---		---		4.1
Other income		3.6		5.0		4.0
Other expense		(11.8)		(7.2)		(9.7)
Net other income (expense)		(3.8)		(2.2)		0.3

INTEREST EXPENSE
Interest on long-term debt		67.3		50.9		50.3
Allowance for borrowed funds used during construction		(4.0)		(4.0)		(4.5)
Interest on short-term debt and other interest charges		15.8		8.0		14.3
Interest expense		79.1		54.9		60.1

INCOME BEFORE TAXES		195.4		234.9		234.1

INCOME TAX EXPENSE		52.4		73.2		84.8

NET INCOME	$	143.0	$	161.7	$	149.3

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS

December 31 (In millions)	2008		2007

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	50.7	$	---
Accounts receivable, less reserve of $2.3 and $3.4 respectively		172.2		134.9
Accrued unbilled revenues		47.0		45.7
Fuel inventories		56.6		44.3
Materials and supplies, at average cost		67.4		59.9
Gas imbalances		0.6		0.1
Accumulated deferred tax assets		12.7		11.4
Fuel clause under recoveries		24.0		27.3
Prepayments		8.0		3.8
Other		2.3		4.2
Total current assets		441.5		331.6

OTHER PROPERTY AND INVESTMENTS, at cost		3.6		3.1

PROPERTY, PLANT AND EQUIPMENT
In service		6,101.1		5,363.1
Construction work in progress		169.1		112.4
Total property, plant and equipment		6,270.2		5,475.5
Less accumulated depreciation		2,314.7		2,241.9
Net property, plant and equipment		3,955.5		3,233.6

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		14.6		17.4
Regulatory asset – SFAS No. 158		344.7		174.6
McClain Plant deferred expenses		6.2		12.4
Unamortized loss on reacquired debt		17.7		18.9
Unamortized debt issuance costs		11.4		6.4
Other		56.0		76.9
Total deferred charges and other assets		450.6		306.6

TOTAL ASSETS	$	4,851.2	$	3,874.9

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS (Continued)

December 31 (In millions)	2008		2007

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Short-term debt	$	---	$	0.8
Accounts payable - affiliates		6.4		10.5
Accounts payable - other		105.0		164.3
Advances from parent		17.6		348.0
Customer deposits		56.8		53.6
Accrued taxes		27.9		24.9
Accrued interest		33.2		21.5
Accrued compensation		25.1		28.8
Price risk management		---		1.7
Fuel clause over recoveries		8.6		4.2
Other		26.8		17.6
Total current liabilities		307.4		675.9

LONG-TERM DEBT		1,541.4		843.4

COMMITMENTS AND CONTINGENCIES (NOTE 13)

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		261.9		118.1
Accumulated deferred income taxes		722.8		633.0
Accumulated deferred investment tax credits		17.3		22.0
Accrued removal obligations, net		150.9		139.7
Other		25.2		19.5
Total deferred credits and other liabilities		1,178.1		932.3

STOCKHOLDER’S EQUITY
Common stockholder’s equity		958.4		665.4
Retained earnings		865.9		757.9
Total stockholder’s equity		1,824.3		1,423.3

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	4,851.2	$	3,874.9

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CAPITALIZATION

December 31 (In millions)		2008		2007

STOCKHOLDER’S EQUITY
Common stock, par value $2.50 per share; authorized 100.0 shares;
and outstanding 40.4 shares		$	100.9	$	100.9
Premium on capital stock			857.5		564.5
Retained earnings			865.9		757.9
Total stockholder’s equity			1,824.3		1,423.3

LONG-TERM DEBT
SERIES	DATE DUE
Senior Notes
5.15%	Senior Notes, Series Due January 15, 2016		110.0		110.0
6.50%	Senior Notes, Series Due July 15, 2017		125.0		125.0
6.35%	Senior Notes, Series Due September 1, 2018		250.0		---
8.25%	Senior Notes, Series Due January 15, 2019		250.0		---
6.65%	Senior Notes, Series Due July 15, 2027		125.0		125.0
6.50%	Senior Notes, Series Due April 15, 2028		100.0		100.0
6.50%	Senior Notes, Series Due August 1, 2034		140.0		140.0
5.75%	Senior Notes, Series Due January 15, 2036		110.0		110.0
6.45%	Senior Notes, Series Due February 1, 2038		200.0		---
Other Bonds
1.40% - 8.35% Garfield Industrial Authority, January 1, 2025			47.0		47.0
1.24% - 8.14% Muskogee Industrial Authority, January 1, 2025			32.4		32.4
1.35% - 7.75% Muskogee Industrial Authority, June 1, 2027			55.9		56.0

Unamortized discount			(3.9)		(2.0)
Total long-term debt			1,541.4		843.4

Total Capitalization		$	3,365.7	$	2,266.7

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY

				Accumulated
		Premium		Other
	Common	on Capital	Retained	Comprehensive
(In millions)	Stock	Stock	Earnings	Income (Loss)	Total

Balance at December 31, 2005	$ 100.9	$ 564.5	$ 530.7	$ (80.1)	$ 1,116.0
Comprehensive income
Net income for 2006	---	---	149.3	---	149.3
Other comprehensive income, net of tax
Minimum pension liability adjustment, net of tax ($130.7 pre-tax)	---	---	---	80.1	80.1
Deferred hedging gains, net of tax ($0.9 pre-tax)	---	---	---	0.6	0.6
Other comprehensive income	---	---	---	80.7	80.7
Comprehensive income	---	---	149.3	80.7	230.0
Dividends declared on common stock	---	---	(24.0)	---	(24.0)
Balance at December 31, 2006	100.9	564.5	656.0	0.6	1,322.0
Comprehensive income
Net income for 2007	---	---	161.7	---	161.7
Other comprehensive income, net of tax
Deferred hedging losses, net of tax (($0.9) pre-tax)	---	---	---	(0.6)	(0.6)
Other comprehensive loss	---	---	---	(0.6)	(0.6)
Comprehensive income	---	---	161.7	(0.6)	161.1
Dividends declared on common stock	---	---	(56.0)	---	(56.0)
FIN No. 48 adoption (($6.2) pre-tax)	---	---	(3.8)	---	(3.8)
Balance at December 31, 2007	$ 100.9	$ 564.5	$ 757.9	$ ---	$ 1,423.3
Comprehensive income
Net income for 2008	---	---	143.0	---	143.0
Comprehensive income	---	---	143.0	---	143.0
Dividends declared on common stock	---	---	(35.0)	---	(35.0)
Capital contribution from parent	---	293.0	---	---	293.0
Balance at December 31, 2008	$ 100.9	$ 857.5	$ 865.9	$ ---	$ 1,824.3

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

Year ended December 31 (In millions)	2008		2007		2006

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	143.0	$	161.7	$	149.3
Adjustments to reconcile net income to net cash provided from operating
activities
Depreciation and amortization		155.0		141.3		132.2
Deferred income taxes and investment tax credits, net		87.2		3.6		11.3
Allowance for equity funds used during construction		---		---		(4.1)
Loss on retirement and abandonment of fixed assets		---		3.8		6.0
Write-down of regulatory assets		9.2		---		---
Price risk management assets		---		0.9		(0.8)
Price risk management liabilities		(1.7)		1.7		(0.1)
Other assets		1.6		(12.7)		(56.4)
Other liabilities		(30.0)		(53.4)		12.9
Change in certain current assets and liabilities
Accounts receivable, net		(37.3)		3.3		16.1
Accrued unbilled revenues		(1.3)		(6.0)		2.1
Fuel, materials and supplies inventories		(19.8)		(19.6)		(4.1)
Gas imbalance assets		(0.5)		(0.1)		---
Fuel clause under recoveries		3.3		(27.3)		101.1
Other current assets		(2.3)		1.5		5.6
Accounts payable		(59.3)		69.1		(17.9)
Accounts payable - affiliates		(4.1)		5.3		(5.5)
Income taxes payable - affiliates		(64.2)		44.3		12.3
Customer deposits		3.2		2.7		4.6
Accrued taxes		3.0		0.8		1.2
Accrued interest		11.7		(6.9)		5.8
Accrued compensation		(3.7)		4.6		4.1
Gas imbalance liabilities		---		---		(0.2)
Fuel clause over recoveries		4.4		(92.1)		96.3
Other current liabilities		9.0		3.6		(16.7)
Net Cash Provided from Operating Activities		206.4		230.1		455.1

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(840.1)		(377.3)		(411.1)
Proceeds from sale of assets		0.5		0.9		1.0
Net Cash Used in Investing Activities		(839.6)		(376.4)		(410.1)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		743.0		---		217.5
Capital contribution from parent		293.0		---		---
Dividends paid on common stock		(35.0)		(56.0)		(39.0)
Retirement of long-term debt		(50.1)		(0.1)		---
Increase (decrease) in short-term debt, net		(267.0)		202.4		(223.5)
Net Cash Provided from (Used in) Financing Activities		683.9		146.3		(45.0)

NET CHANGE IN CASH AND CASH EQUIVALENTS		50.7		---		---
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		---		---		---

CASH AND CASH EQUIVALENTS AT END OF PERIOD

50.7

---

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

OKLAHOMA GAS AND ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

1.	Summary of Significant Accounting Policies

Organization

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”) which 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 was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

Accounting Records

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

The following table is a summary of the Company’s regulatory assets and liabilities at December 31:

December 31(In millions)	2008		2007
Regulatory Assets
Regulatory asset – SFAS No. 158	$	344.7	$	174.6
Deferred storm expenses		32.2		35.9
Fuel clause under recoveries		24.0		27.3
Unamortized loss on reacquired debt		17.7		18.9
Income taxes recoverable from customers, net		14.6		17.4
Deferred pension plan expenses		14.6		24.8
Red Rock deferred expenses		7.4		14.7
McClain Plant deferred expenses		6.2		12.4
Cogeneration credit rider under recovery		1.4		3.9
Miscellaneous		1.5		0.8
Total Regulatory Assets	$	464.3	$	330.7

Regulatory Liabilities
Accrued removal obligations, net	$	150.9	$	139.7
Fuel clause over recoveries		8.6		4.2
Miscellaneous		4.5		4.3
Total Regulatory Liabilities	$	164.0	$	148.2

The Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which required the Company to separately disclose the items that had not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required these charges to be included in Accumulated Other Comprehensive Income. However, for

companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. The Company met both criteria and, therefore, recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

The following table is a summary of the components of the SFAS No. 158 regulatory asset at December 31:

December 31 (In millions)	2008		2007
Defined benefit pension plan and restoration of retirement income plan:
Net loss	$	259.8	$	112.3
Prior service cost		3.5		4.8
Defined benefit postretirement plans:
Net loss		70.4		42.5
Net transition obligation		10.2		12.7
Prior service cost		0.8		2.3
Total	$	344.7	$	174.6

The following amounts in the SFAS No. 158 regulatory asset at December 31, 2008 are expected to be recognized as components of net periodic benefit cost in 2009:

(In millions)
Defined benefit pension plan and restoration of retirement income plan:
Net loss	$	20.4
Prior service cost		1.2
Defined benefit postretirement plans:
Net loss		3.6
Net transition obligation		2.5
Prior service cost		1.5
Total	$	29.2

Fuel clause under recoveries are generated from under recoveries from the Company’s customers when the Company’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from the Company’s customers when the amount billed to its customers exceeds the Company’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under and over recovery balances.

For a discussion of regulatory matters related to the deferred storm expenses and deferred Red Rock expenses and related reductions in the amounts previously recorded, see Note 14.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of the Company’s long-term debt. These amounts are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is not included in the Company’s rate base and does not otherwise earn a rate of return.

In accordance with the OCC order received by the Company in December 2005 in its Oklahoma rate case, the Company was allowed to recover a certain amount of pension plan expenses. At December 31, 2008, there was approximately $14.6 million of expenses exceeding this level primarily related to pension settlement charge recorded by the Company during 2007 (see Note 12 for a further discussion). These excess amounts have been recorded as a regulatory asset as the Company believes these expenses are probable of future recovery.

Income taxes recoverable from customers represent income tax benefits previously used to reduce the Company’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as

regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The income tax related regulatory assets and liabilities are netted on the Company’s Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.” The OCC authorized approximately $30.1 million of the $32.8 million regulatory asset balance at December 31, 2005 to be included in the Company’s rate base for purposes of earning a return.

As a result of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the 2002 agreed-upon settlement of a Company rate case with the OCC, the Company had the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. At December 31, 2008, the McClain Plant regulatory asset was approximately $6.2 million which is being recovered over the remaining one-year time period as authorized in the OCC rate order which began in January 2006. Approximately $15.5 million of the McClain Plant deferred expenses are included in the Company’s rate base for purposes of earning a return.

The Company’s cogeneration credit rider was initially implemented in 2003 as part of the Oklahoma retail customer electric rates in order to return purchase power capacity payment reductions and any change in operating and maintenance expense related to cogeneration previously included in base rates to the Company’s customers. The cogeneration credit rider has been updated and approved by the OCC in December of each year through December 2007 and any over/under recovery of the cogeneration credit rider in the current year and prior periods was automatically included in the next year’s rider. The Company’s current cogeneration credit rider expires on December 31, 2009. The balance of the cogeneration credit rider under recovery was approximately $1.4 million and $3.9 million, respectively, at December 31, 2008 and 2007. The cogeneration credit rider under recovery was not included in the Company’s rate base and did not otherwise earn a rate of return. The cogeneration credit rider under recovery is included in Other Current Assets on the Company’s Balance Sheets.

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations.

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

Use of Estimates

In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, asset retirement obligations (“ARO”), fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable.

Cash and Cash Equivalents

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

Allowance for Uncollectible Accounts Receivable

expense recognized. The allowance for uncollectible accounts receivable was approximately $2.3 million and $3.4 million at December 31, 2008 and 2007, respectively.

New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. Historically, the Company has used the last-in, first-out (“LIFO”) method of accounting for inventory removed from storage or stockpiles. Effective January 1, 2008, the Company began using the weighted-average cost method to value inventory that is physically added to or withdrawn from storage or stockpiles in accordance with Oklahoma Senate Bill No. 609 (“SB 609”) that was adopted in Oklahoma in 2007. SB 609 requires that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. In addition to satisfying the requirements of SB 609, management believes that the change from LIFO to weighted-average cost is also preferable because it provides for a more meaningful presentation in the financial statements taken as a whole and reduces the volatility associated with fuel price fluctuations on the Company’s customers. The majority of electric utility companies use the weighted-average cost method.

SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (“APB”) Opinion No. 20 and FASB Statement No. 3,” requires that an entity report a change in accounting principle through retrospective application of the new principle to all prior periods unless it is impractical to do so. However, SFAS No. 71 requires that changes in accounting methods for regulated entities that affect allowable costs for rate-making purposes should be implemented in the same way that such an accounting change would be implemented for rate-making purposes. In accordance with an order from the OCC, the Company’s change in accounting method for inventory affected allowable costs for rate-making purposes, on a prospective basis only beginning January 1, 2008. Therefore the change in accounting was implemented prospectively for purposes of generally accepted accounting principles (“GAAP”) and the Company did not restate previously issued financial statements. Also, in accordance with the order from the OCC, on January 1, 2008, the Company recorded an increase in Fuel Inventories of approximately $7.9 million with a corresponding offset recorded in Fuel Clause Under and Over Recoveries on the Company’s Financial Statements. The Company began recovering costs from its customers using the weighted-average cost method for inventory on January 1, 2008.

The change in accounting for fuel inventory to the weighted-average cost method resulted in a higher fuel inventory balance of approximately $0.4 million at December 31, 2008. The change in accounting for fuel inventory to the weighted-average cost method did not impact the income statement for the year ended December 31, 2008 as the Company’s fuel costs are passed through to its customers through fuel adjustment clauses.

The amount of fuel inventory was approximately $56.6 million and $44.3 million at December 31, 2008 and 2007, respectively. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $7.4 million for 2007 based on the average cost of fuel purchased.

Property, Plant and Equipment

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction (“AFUDC”). Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property less net salvage is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance is recorded as a loss in the Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Statements of Income as Other Operation and Maintenance Expense.

The below table presents the Company’s ownership interest in the jointly-owned McClain Plant and the jointly-owned 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (the “Redbud Facility”), and, as disclosed below, only the Company’s ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in this table. The owners of the remaining interests in the McClain Plant and the Redbud Facility are

responsible for providing their own financing of capital expenditures. Also, only the Company’s proportionate interests of any direct expenses of the McClain Plant and the Redbud Facility such as fuel, maintenance expense and other operating expenses are included in the applicable financial statements captions in the Statements of Income.

	Percentage	Total Property, Plant	Accumulated	Net Property, Plant and
December 31, 2008 (In millions)	Ownership	and Equipment	Depreciation	Equipment
McClain Plant	77	$ 181.0	$ 44.6	$ 136.4
Redbud Facility	51	$ 496.6 (A)	$ 63.9 (B)	$ 432.7

(A)

This amount includes a plant acquisition adjustment of approximately $153.7 million.

(B)	This amount includes accumulated amortization of the plant acquisition adjustment of approximately $1.5 million.

	Percentage	Total Property, Plant	Accumulated	Net Property, Plant and
December 31, 2007 (In millions)	Ownership	and Equipment	Depreciation	Equipment
McClain Plant	77	$ 181.0	$ 35.4	$ 145.6

The Company’s property, plant and equipment and related accumulated depreciation are divided into the following major classes at December 31, 2008 and 2007, respectively.

	Total Property,				Net Property,
	Plant and		Accumulated		Plant and
December 31, 2008 (In millions)	Equipment		Depreciation		Equipment
Distribution assets	$	2,551.5	$	824.8	$	1,726.7
Electric generation assets		2,623.8		1,095.4		1,528.4
Transmission assets		846.1		299.8		546.3
Intangible plant		26.8		18.4		8.4
Other property and equipment		222.0		76.3		145.7
Total property, plant and equipment	$	6,270.2	$	2,314.7	$	3,955.5

	Total Property,				Net Property,
	Plant and		Accumulated		Plant and
December 31, 2007 (In millions)	Equipment		Depreciation		Equipment
Distribution assets	$	2,361.4	$	792.0	$	1,569.4
Electric generation assets		2,114.0		1,062.8		1,051.2
Transmission assets		747.3		285.7		461.6
Intangible plant		35.8		29.7		6.1
Other property and equipment		217.0		71.7		145.3
Total property, plant and equipment	$	5,475.5	$	2,241.9	$	3,233.6

Depreciation and Amortization

The provision for depreciation, which was approximately 2.7 percent of the average depreciable utility plant for both 2008 and 2007, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method. In 2009, the provision for depreciation is projected to be approximately 2.8 percent of the average depreciable utility plant. Amortization of intangibles is computed using the straight-line method. Approximately 6.3 percent of the remaining amortizable intangible plant balance at December 31, 2008 will be amortized over three years with approximately 37 percent of the remaining amortizable intangible plant balance at December 31, 2008 being amortized over their respective lives ranging from four to 25 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life on the acquired asset. Plant acquisition adjustments include approximately $153.7 million for the Redbud Facility, which will be amortized over a 27-year life and approximately $0.5 million for certain substation facilities in the Company’s service territory, which will be amortized over a 26 to 59-year period.

Asset Retirement Obligations

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” for periods subsequent to the initial measurement of an ARO, the Company recognizes period-to-period changes in the liability for an ARO resulting from: (i) the passage of time; and (ii) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

Also, in accordance with FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional ARO is recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information existed. However, in some cases, there is insufficient information to estimate the fair value of an ARO. In these cases, the liability is initially recognized in the period in which sufficient information is available for the Company to make a reasonable estimate of the liability’s fair value. The Company did not recognize any new AROs during 2008; however, the Company has identified certain AROs that have not been recorded because the Company determined that these assets, primarily related to the Company’s power plant sites, have indefinite lives.

Allowance for Funds Used During Construction

AFUDC is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. AFUDC, a non-cash item, is reflected as a credit in the Statements of Income and as a charge to Construction Work in Progress in the Balance Sheets. AFUDC rates, compounded semi-annually, were 3.58 percent, 5.78 percent and 7.79 percent for the years 2008, 2007 and 2006, respectively. The decrease in the AFUDC rates in 2008 was primarily due to lower interest rates on short-term borrowings.

Collection of Sales Tax

In the course of its operations, the Company collects sales tax from its customers. The Company records a current liability from sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. The Company excludes the sales tax collected from its operating revenues.

Revenue Recognition

General

The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

SPP Purchases and Sales

In February 2007, the Company began participating in the Southwest Power Pool’s (“SPP”) energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including the Company, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ megawatt-hour (“MWH”) entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. The Company records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Financial Statements.

Fuel Adjustment Clauses

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to the Company’s customers through fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.

Accrued Vacation

The Company accrues vacation pay by establishing a liability for vacation earned during the current year, but not payable until the following year.

Environmental Costs

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company’s estimated share of the cost.

Related Party Transactions

OGE Energy allocated operating costs to the Company of approximately $87.4 million, $96.4 million and $88.0 million during 2008, 2007 and 2006, respectively. OGE Energy allocates operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

In 2008, 2007 and 2006, the Company recorded an expense from its affiliate, Enogex LLC and its subsidiaries (“Enogex”), of approximately $34.8 million, $34.7 million and $34.9 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In each of 2008, 2007 and 2006, the Company recorded an expense from Enogex of approximately $12.7 million for natural gas storage services. In 2008, 2007 and 2006, the Company also recorded natural gas purchases from its affiliate, OGE Energy Resources, Inc. (“OERI”) of approximately $79.6 million, $55.2 million and $60.4 million, respectively. Approximately $6.6 million and $11.3 million were recorded at December 31, 2008 and 2007, respectively, and are included in Accounts Payable – Affiliates in the Balance Sheet for these activities.

In both 2008 and 2007, the Company recorded interest income of less than $0.1 million from OGE Energy for advances made to OGE Energy from the Company. In 2006, the Company recorded interest income of approximately $0.3 million from OGE Energy for advances made to OGE Energy by the Company.

In 2008, 2007 and 2006, the Company recorded interest expense of approximately $2.1 million, $6.1 million and $2.6 million, respectively, to OGE Energy for advances made by OGE Energy to the Company. The interest rate charged on advances to the Company from OGE Energy approximates OGE Energy’s commercial paper rate.

In 2008, 2007 and 2006, the Company declared dividends of approximately $35.0 million, $56.0 million and $24.0 million, respectively, to OGE Energy.

On September 25, 2008, OGE Energy made a capital contribution to the Company for approximately $293.0 million.

2.	Accounting Developments

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which requires enhanced disclosures about an entity’s derivative and hedging activities and is intended to improve the transparency of financial reporting. SFAS No. 161 applies to all entities. SFAS No. 161 applies to all derivative instruments, including bifurcated derivative instruments and related hedging items accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company adopted this new standard effective January 1,

2009. The adoption of this new standard will change the disclosure related to derivative and hedging activities in the Company’s financial statements.

In 2004, the Company adopted a standard costing model utilizing a fully loaded activity rate (including payroll, benefits, other employee related costs and overhead costs) to be applied to projects eligible for capitalization or deferral. In March 2008, the Company determined that the application of the fully loaded activity rates had unintentionally resulted in the over-capitalization of immaterial amounts of certain payroll, benefits, other employee related costs and overhead costs in prior years. To correct this issue, in March 2008, the Company recorded a pre-tax charge of approximately $9.5 million ($5.8 million after tax) as an increase in Other Operation and Maintenance Expense in the Condensed Statements of Operations for the three months ended March 31, 2008 and a corresponding $8.6 million decrease in Construction Work in Progress and $0.9 million decrease in Other Deferred Charges and Other Assets related to the regulatory asset associated with storm costs in the Condensed Balance Sheets as of March 31, 2008.

3.	Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in GAAP and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the guidance in footnote 3 of Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF Issue No. 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 generally are to be applied prospectively as of the beginning of the fiscal year in which it is initially applied. The Company adopted this new standard effective January 1, 2008.

The following table is a summary of the Company’s liabilities that are measured at fair value on a recurring basis in accordance with SFAS No. 157. At December 31, 2008, the Company had no assets measured at fair value on a recurring basis in accordance with SFAS No. 157.

	December 31,
(In millions)	2008		Level 3
Liabilities
Asset retirement obligations	$	5.2	$ 5.2
Total	$	5.2	$ 5.2

The three levels defined by the SFAS No. 157 hierarchy and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available. Unobservable inputs shall reflect the reporting entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions. An example of

instruments that may be classified as Level 3 includes the valuation of ARO’s such that there are no closely related markets in which quoted prices are available.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services (“Standard & Poor’s”) and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material. The Company has no derivatives at December 31, 2008.

The following table is a summary of the Company’s liabilities that are measured at fair value on a recurring basis in accordance with SFAS No. 157 using significant unobservable inputs (Level 3).

	Year Ended
(In millions)	December 31, 2008
Asset Retirement Obligations
Beginning balance	$	4.9
Total gains or losses (realized/unrealized)
Included in earnings		0.3
Included in other comprehensive income		---
Purchases, sales, issuances and settlements, net		---
Transfers in and/or out of Level 3		---
Ending balance	$	5.2
The amount of total gains or losses for the periods included in earnings attributable to the change in unrealized gains or losses relating to assets held at December 31, 2008	$	---

Gains and losses (realized and unrealized) included in earnings for the year ended December 31, 2008 attributable to the change in unrealized gains or losses relating to liabilities held at December 31, 2008, if any, are reported in operating revenues.

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, as of December 31:

	2008				2007
	Carrying		Fair		Carrying		Fair
December 31(In millions)	Amount		Value		Amount		Value

Price Risk Management Liabilities
Interest Rate Swap	$	---	$	---	$	1.7	$	1.7

Long-Term Debt
Senior Notes	$	1,406.1	$	1,327.4	$	708.0	$	729.2
Industrial Authority Bonds		135.3		135.3		135.4		135.4

The carrying value of the financial instruments on the Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swap was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

4.	Stock-Based Compensation

On January 21, 1998, OGE Energy adopted a Stock Incentive Plan (the “1998 Plan”) and in 2003, OGE Energy adopted another Stock Incentive Plan (the “2003 Plan” that replaced the 1998 Plan). In 2008, OGE Energy adopted, and its shareowners approved, a new Stock Incentive Plan (the “2008 Plan” and together with the 1998 Plan and the 2003 Plan, the “Plans”). The 2008 Plan replaced the 2003 Plan and no further awards will be granted under the 2003 Plan or the 1998 Plan. As under the 2003 Plan and the 1998 Plan, under the 2008 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 2,750,000 shares under the 2008 Plan.

Effective January 1, 2006, OGE Energy adopted SFAS No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method. Under that transition method, the Company’s compensation cost recognized in the first quarter of 2006 included: (i) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R); and (ii) compensation cost for all share-based payments granted in the first quarter of 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R). Results for prior periods were not restated. As a result of adopting SFAS No. 123(R) on January 1, 2006, the Company recorded compensation expense of approximately $1.8 million pre-tax ($1.1 million after tax) in 2006 related to the Company’s portion of OGE Energy’s share-based payments.

The Company recorded compensation expense of approximately $1.0 million pre-tax ($0.6 million after tax) and approximately $0.9 million pre-tax ($0.6 million after tax) in 2008 and 2007, respectively, related to the Company’s portion of OGE Energy’s share-based payments. Also, during 2008, OGE Energy converted 166,504 performance units based on a payout ratio of 147.33 percent of the target number of performance units granted in February 2005, of which 36,941 performance units related to the Company’s portion. One-third of the performance units were settled in cash for approximately $3.0 million, of which approximately $0.7 million was the Company’s portion, and two-thirds of the performance units were settled in the Company’s common stock.

OGE Energy issues new shares to satisfy stock option exercises and payouts of earned performance units. During 2008, 2007 and 2006, there were 875,434 shares, 496,565 shares and 738,426 shares, respectively, of new common stock issued pursuant to OGE Energy’s Plans related to exercised stock options and payouts of earned performance units, of which 38,684, 129,568 and 299,331 shares, respectively, related to the Company’s employees. OGE Energy received approximately $15.0 million, $8.2 million and $14.5 million in 2008, 2007 and 2006, respectively, related to exercised stock options.

Performance Units

Under the Plans, OGE Energy has issued performance units which represent the value of one share of OGE Energy’s common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Plans). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant’s number of full months of service during the three-year award cycle, further adjusted based on the achievement of the performance goals during the award cycle.

The performance units granted based on total shareholder return (“TSR”) are contingently awarded and will be payable in shares of OGE Energy’s common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a three-year award cycle (i.e. three-year cliff vesting period) is dependent on OGE Energy’s TSR ranking relative to a peer group of companies. The performance units granted based on earnings per share (“EPS”) are contingently awarded and will be payable in shares of OGE Energy’s common stock based on OGE Energy’s EPS growth over a three-year award cycle (i.e. three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy’s Board of Directors. All of the Company’s performance units are classified as equity under SFAS No. 123(R). If there is no or only a partial payout for the performance units at the end of the three-year award cycle, the unearned performance units are cancelled. During 2008, 2007 and 2006, OGE Energy awarded 242,503, 162,730 and 239,856 performance units, respectively, to certain employees of OGE Energy and its subsidiaries, of which 43,508, 27,322 and 34,459, respectively, related to the Company’s employees.

Performance Units – Total Shareholder Return

The Company recorded compensation expense of approximately $0.7 million pre-tax ($0.4 million after tax), $0.6 million pre-tax ($0.4 million after tax) and $1.4 million pre-tax ($0.9 million after tax) in 2008, 2007 and 2006, respectively, related to the performance units based on TSR. The fair value of the performance units based on TSR was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. Expected price volatility is based on the historical volatility of OGE Energy’s common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to

OGE Energy’s performance units based on TSR. The fair value of the performance units based on TSR was calculated based on the following assumptions at the grant date.

	2008	2007	2006
Expected dividend yield	3.8%	3.6%	4.9%
Expected price volatility	18.7%	15.9%	16.8%
Risk-free interest rate	2.21%	4.47%	4.66%
Expected life of units (in years)	2.84	2.95	2.85
Fair value of units granted	$ 33.62	$ 24.18	$ 22.93

A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on TSR at December 31, 2008 and changes during 2008 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on TSR is determined by OGE Energy’s TSR for such period compared to a peer group and payout requires the approval of the Compensation Committee of OGE Energy’s Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

		Stock	Aggregate
	Number	Conversion	Intrinsic
(dollars in millions)	of Units	Ratio (A)	Value
Units Outstanding at 12/31/07	72,638	1:1
Granted (B)	32,635	1:1
Converted	(27,710)	1:1	$ 0.7
Forfeited	(590)	1:1
Employee migration (C)	8,057	1:1
Units Outstanding at 12/31/08	85,030	1:1	$ 1.1
Units Fully Vested at 12/31/08 (D)	29,662	1:1	$ 0.9

(A) One performance unit = one share of OGE Energy’s common stock.

(B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(D) These performance units, which were awarded in 2006 and became fully vested at December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009.

A summary of the activity for OGE Energy’s non-vested performance units applicable to the Company’s employees based on TSR at December 31, 2008 and changes during 2008 are summarized in the following table:

		Weighted-Average
	Number	Grant Date
	of Units	Fair Value
Units Non-Vested at 12/31/07	44,928	$ 23.43
Granted (E)	32,635	$ 33.62
Vested (F)	(29,662)	$ 22.93
Forfeited	(590)	$ 33.62
Employee migration (G)	8,057	$ 27.44
Units Non-Vested at 12/31/08 (H)	55,368	$ 30.18

(E) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(F) These performance units, which were awarded in 2006 and became fully vested at December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009.

(G) Due to certain employees transferring between OGE Energy and its subsidiaries.

(H) Of the 55,368 performance units not vested at December 31, 2008, 47,133 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2008, there was approximately $0.7 million in unrecognized compensation cost related to non-vested performance units based on TSR which is expected to be recognized over a weighted-average period of 1.84 years.

Performance Units – Earnings Per Share

The Company recorded compensation expense of approximately $0.3 million pre-tax ($0.2 million after tax), $0.3 million pre-tax ($0.2 million after tax) and $0.4 million pre-tax ($0.2 million after tax) in 2008, 2007 and 2006, respectively, related to the performance units based on EPS. The fair value of the performance units based on EPS is based on grant date fair value which is equivalent to the price of one share of OGE Energy’s common stock on the date of grant. The fair value of performance units based on EPS varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. OGE Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to OGE Energy’s performance units based on EPS. The grant date fair value of the 2006, 2007 and 2008 performance units was $28.00, $33.59 and $29.22, respectively.

A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on EPS at December 31, 2008 and changes during 2008 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on EPS growth is determined by OGE Energy’s growth in EPS for such period compared to a target set at the beginning of the three-year period by the Compensation Committee of OGE Energy’s Board of Directors and payout requires the approval of the Compensation Committee. Payouts, if any, are all made in common stock and are considered made when approved by the Compensation Committee.

		Stock	Aggregate
	Number	Conversion	Intrinsic
(dollars in millions)	of Units	Ratio (A)	Value
Units Outstanding at 12/31/07	24,149	1:1
Granted (B)	10,873	1:1
Converted	(9,231)	1:1	$ 0.4
Forfeited	(196)	1:1
Employee migration (C)	2,686	1:1
Units Outstanding at 12/31/08	28,281	1:1	$ 0.5
Units Fully Vested at 12/31/08 (D)	9,885	1:1	$ 0.5

(A) One performance unit = one share of OGE Energy’s common stock.

(B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(D) These performance units, which were awarded in 2006 and became fully vested December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009.

A summary of the activity for OGE Energy’s non-vested performance units applicable to the Company’s employees based on EPS at December 31, 2008 and changes during 2008 are summarized in the following table:

		Weighted-Average
	Number	Grant Date
	of Units	Fair Value
Units Non-Vested at 12/31/07	14,918	$ 30.24
Granted (E)	10,873	$ 29.22
Vested (F)	(9,885)	$ 28.00
Forfeited	(196)	$ 29.22
Employee migration (G)	2,686	$ 29.90
Units Non-Vested at 12/31/08 (H)	18,396	$ 30.80

(E) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(G) Due to certain employees transferring between OGE Energy and its subsidiaries.

(H) Of the 18,396 performance units not vested at December 31, 2008, 15,708 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2008, there was approximately $0.2 million in unrecognized compensation cost related to non-vested performance units based on EPS which is expected to be recognized over a weighted-average period of 2.0 years.

Stock Options

The Company recorded no compensation expense in 2008 or 2007 related to stock options because at December 31, 2006, there was no unrecognized compensation cost related to non-vested options, which became fully vested in January 2007. The Company recorded compensation expense of less than $0.1 million pre-tax and after tax in 2006 related to stock options.

A summary of the activity for OGE Energy’s options applicable to the Company’s employees at December 31, 2008 and changes during 2008 are summarized in the following table:

			Aggregate	Weighted-Average
	Number	Weighted-Average	Intrinsic	Remaining
(dollars in millions)	of Options	Exercise Price	Value	Contractual Term
Options Outstanding at 12/31/07	62,212	$ 22.64
Exercised	(3,100)	$ 24.66	$ ---
Employee migration	18,300	$ 21.27
Expired	---	$ ---
Options Outstanding at 12/31/08	77,412	$ 22.21	$ 0.3	4.97 years
Options Fully Vested and Exercisable at 12/31/08	77,412	$ 22.21	$ 0.3	4.97 years

Restricted Stock

Under the Plans and in the third quarter of 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture. During 2008, OGE Energy awarded 56,798 shares of restricted stock, of which 21,618 shares of restricted stock related to the Company’s employees.

The Company recorded compensation expense of approximately $0.1 million pre-tax ($0.1 million after tax) in 2008 related to the restricted stock. The fair value of the restricted stock was based on the closing market price of OGE Energy’s common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a three-year vesting period. Also, the Company treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the restricted stock is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy’s restricted stock. The weighted-average grant date fair value of the 2008 restricted stock was $30.88.

At December 31, 2008, there was approximately $0.6 million in unrecognized compensation cost related to non-vested restricted stock which is expected to be recognized over a weighted-average period of 2.75 years.

5.	Loss on Retirement and Asset Retirement Obligation of Fixed Assets

The Company had a power supply contract with a large industrial customer that expired on June 1, 2006. The Company evaluated options to utilize the assets dedicated to that customer and decided to retire these assets as of June 30, 2006. The carrying amount of these assets at June 30, 2006 was approximately $6.8 million, which was recorded as a pre-tax loss during the second quarter of 2006. This loss was included in Other Expense in the Statement of Income. Also, as part of the settlement of the ARO for these assets, the Company recorded a reduction to the previously recorded ARO for these assets of approximately $0.9 million in 2006 due to an agreement with a third party to provide removal and remediation services. This reduction is included in Other Expense in the Statement of Income.

6.	Price Risk Management Assets and Liabilities

The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During 2007, the Company’s use of price risk management instruments involved the use of treasury lock agreements. The treasury lock agreements help protect against the variability of future interest payments of long-term debt that was issued by the Company. The Company has no derivatives at December 31, 2008.

In accordance with SFAS No. 133, the Company recognizes its non-exchange traded derivative instruments as Price Risk Management assets or liabilities in the Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

The Company measures the ineffectiveness of treasury lock cash flow hedges using the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected.

At December 31, 2007, the Company’s treasury lock agreements were not designated as cash flow hedges under SFAS No. 133. The 2007 treasury lock agreements were settled on January 29, 2008.

7.	Supplemental Cash Flow Information

The following table discloses information about investing and financing activities that affect recognized assets and liabilities but which do not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.

Year ended December 31 (In millions)	2008		2007		2006
NON-CASH INVESTING AND FINANCING ACTIVITIES

Power plant long-term service agreement	$	3.5	$	0.7	$	---
Capital lease for distribution equipment		0.3		---		---

SUPPLEMENTAL CASH FLOW INFORMATION

Cash Paid During the Period for
Interest (net of interest capitalized of $4.0, $4.0, $4.5)	$	67.1	$	57.9	$	50.5
Income taxes (net of income tax refunds)		29.3		30.2		61.0

8.	Income Taxes

The items comprising income tax expense are as follows:

Year ended December 31 (In millions)	2008		2007		2006
Provision (Benefit) for Current Income Taxes
Federal	$	(30.2)	$	68.3	$	81.6
State		(3.6)		0.6		(7.7)
Total Provision (Benefit) for Current Income Taxes		(33.8)		68.9		73.9
Provision (Benefit) for Deferred Income Taxes, net
Federal		92.1		6.9		15.3
State		(0.3)		1.5		1.0
Total Provision for Deferred Income Taxes, net		91.8		8.4		16.3
Deferred Federal Investment Tax Credits, net		(4.6)		(4.8)		(5.0)
Income Taxes Relating to Other Income and Deductions		(1.0)		0.7		(0.4)
Total Income Tax Expense	$	52.4	$	73.2	$	84.8

The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2005. In September 2008, the Internal Revenue Service (“IRS”) completed its audit of tax years 2005 and 2006. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its Federal investment tax credits on a ratable basis throughout the year. In addition, the Company earns both Federal and Oklahoma state tax credits associated with the production from its 120 MW wind farm in northwestern Oklahoma (“Centennial”) wind farm that further reduce the Company’s effective tax rate. The following schedule reconciles the statutory Federal tax rate to the effective income tax rate:

Year ended December 31	2008	2007	2006
Statutory Federal tax rate	35.0%	35.0%	35.0%
Amortization of net unfunded deferred taxes	1.3	1.3	1.1
Medicare Part D subsidy	(0.4)	(0.3)	(0.9)
State income taxes, net of Federal income tax benefit	(2.1)	1.2	2.5
Federal investment tax credits, net	(2.4)	(2.0)	(2.1)
Federal renewable energy credit (A)	(4.6)	(3.0)	---
401(k) dividends	---	---	1.3
Other	---	(1.0)	(0.7)
Effective income tax rate as reported	26.8%	31.2%	36.2%

(A) These are credits the Company began earning associated with the production from the Centennial wind farm that was placed in service during January 2007.

The Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of costs for self-constructed assets discussed above. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company reached a final settlement with the IRS on November 27, 2007 related to the tax method of accounting for the capitalization of costs for self-constructed assets. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

December 31(In millions)	2008		2007
Beginning Balance	$	---	$	66.4
Settlements with tax authorities		---		(66.4)
Ending Balance	$	---	$	---

The Company recognizes accrued interest related to tax benefits in interest expense and recognizes penalties in other expense. The Company recorded interest expense associated with the IRS audit of approximately $0.3 million in 2006 and $2.6 million in 2007. On November 27, 2007, the Company reached a final settlement with the IRS related to the tax method of accounting, which resulted in a reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position. At December 31, 2007, the Company had approximately $2.9 million of accrued interest related to the capitalization of costs for self-constructed assets discussed above.

The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.

The deferred tax provisions, set forth above, are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by the Company. The components of Accumulated Deferred Taxes at December 31, 2008 and 2007, respectively, were as follows:

December 31(In millions)	2008		2007
Current Accumulated Deferred Tax Assets
Federal renewable energy credit	$	9.1	$	---
Accrued vacation		4.3		3.9
Uncollectible accounts		1.1		1.4
Accrued liabilities		---		1.2
Derivative instruments		---		0.4
Other		---		4.5
Total Current Accumulated Deferred Tax Assets		14.5		11.4
Current Accumulated Deferred Tax Liabilities
Accrued liabilities		(0.1)		---
Other		(1.7)		---
Total Current Accumulated Deferred Tax Liabilities		(1.8)		---
Current Accumulated Deferred Tax Assets, net	$	12.7	$	11.4
Non-Current Accumulated Deferred Tax Liabilities
Accelerated depreciation and other property related differences	$	734.2	$	633.4
Company pension plan		77.6		62.6
Income taxes refundable to customers, net		5.7		6.7
Bond redemption-unamortized costs		5.7		6.1
Regulatory asset		3.2		7.7
Total Non-Current Accumulated Deferred Tax Liabilities		826.4		716.5
Non-Current Accumulated Deferred Tax Assets
Regulatory liabilities		(58.5)		(54.7)
Postretirement medical and life insurance benefits		(23.5)		(20.3)
State tax credit carryforward		(11.8)		---
Deferred Federal investment tax credits		(6.7)		(8.5)
Other		(3.1)		---
Total Non-Current Accumulated Deferred Tax Assets		(103.6)		(83.5)
Non-Current Accumulated Deferred Income Tax Liabilities, net	$	722.8	$	633.0

The Company currently estimates a Federal tax operating loss for 2008 of approximately $53.2 million primarily caused by the accelerated tax depreciation provisions contained within the Economic Stimulus Act of 2008 (“Stimulus Act”). The Stimulus Act allows a current deduction for 50 percent of the cost of certain property placed into service during 2008. This loss results in an approximately $18.6 current income tax receivable related to the 2008 tax year. It is the Company’s intent to carry this tax loss back to a prior period in order to obtain cash refunds. As noted above, the impact of deferred tax accounting will not cause this refund to impact the effective tax rate.

The Company has an Oklahoma investment tax credit carryover from 2007 of approximately $7.1 million. During 2008, additional Oklahoma tax credits of approximately $16.1 million were generated or purchased by the Company. The Company currently believes that approximately $5.1 million of these state tax credit amounts will be utilized in the 2008 tax

year and approximately $18.1 million will be carried over to the 2009 tax year and later years. The Company’s credits do not have an expiration date.

9.	Common Stock and Cumulative Preferred Stock

There were no new shares of common stock issued during 2008, 2007 or 2006. The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.

10.

Long-Term Debt

A summary of the Company’s long-term debt is included in the Statements of Capitalization. At December 31, 2008, the Company was in compliance with all of its debt agreements.

Optional Redemption of Long-Term Debt

The Company has three series of variable-rate industrial authority bonds (the “Bonds”) with optional redemption provisions that allow the holders to request repayment of the Bonds at various dates prior to the maturity. The Bonds, which can be tendered at the option of the holder during the next 12 months, are as follows (dollars in millions):

SERIES	DATE DUE	AMOUNT
1.40% - 8.35%(A) Garfield Industrial Authority, January 1, 2025		$	47.0
1.24% - 8.14%(A) Muskogee Industrial Authority, January 1, 2025			32.4
1.35% - 7.75%(A) Muskogee Industrial Authority, June 1, 2027			55.9
Total (redeemable during next 12 months)		$	135.3

(A) During the first six months of 2008, the interest rates for the Bonds were between 1.24% and 3.45%. In September 2008, the interest rates for the Bonds significantly increased to a one-week high of 8.35%. Currently, the interest rates for the Bonds are between 0.55 and 0.95%.

All of these Bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the Bond by delivering an irrevocable notice to the tender agent stating the principal amount of the Bond, payment instructions for the purchase price and the business day the Bond is to be purchased. The repayment option may only be exercised by the holder of a Bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of Bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds except as discussed below. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company believes that it has sufficient long-term liquidity to meet these obligations.

In September 2008, the Company received a request for repayment of approximately $0.1 million of principal related to a portion of the Company’s Muskogee Industrial Authority variable-rate bonds, due June 1, 2027. In September 2008, approximately $0.1 million of principal and accrued interest were paid to the bondholder. The $0.1 million of variable-rate industrial authority bonds is being remarketed by the remarketing agent.

Long-Term Debt Maturities

There are no maturities of the Company’s long-term debt during the next five years.

The Company has previously incurred costs related to debt refinancings. Unamortized debt expense and unamortized loss on reacquired debt are classified as Deferred Charges and Other Assets – Other and unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Balance Sheets and are being amortized over the life of the respective debt.

Issuance of Long-Term Debt

In January 2008, the Company issued $200 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings. The Company entered into two separate treasury lock arrangements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and

$25.0 million, respectively, of the long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008.

In December 2008, the Company issued $250 million of 8.25% senior notes due January 15, 2019. The proceeds from the issuance were used to repay borrowings under the Company’s term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC, as discussed in Note 11, and OGE Energy’s and the Company’s revolving credit agreements, which were used to fund the Company’s daily operational needs as well as the Company’s acquisition of the Redbud Facility.

11.

Short-Term Debt

There was no short-term debt outstanding at December 31, 2008. The short-term debt balance was approximately $0.8 million at December 31, 2007. At December 31, 2008 and 2007, the Company had approximately $17.6 million and $348.0 million, respectively, in outstanding advances from OGE Energy. The following table shows OGE Energy’s and the Company’s revolving credit agreements and available cash at December 31, 2008.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate	Amount	Weighted-Average
Entity	Commitment (A)	Outstanding (B)	Interest Rate	Maturity
OGE Energy (C)	$ 596.0	$ 298.0	0.75% (F)	December 6, 2012 (E)
The Company (D)	389.0	---	---% (F)	December 6, 2012 (E)
	985.0	298.0	0.75%
Cash	50.7	N/A	N/A	N/A
Total	$ 1,035.7	$ 298.0	0.75%

(A) All of the lenders that participate in OGE Energy’s and the Company’s revolving credit agreements have funded their commitment, with the exception of Lehman Brothers Holdings, Inc. (“Lehman”), which filed for bankruptcy protection on September 15, 2008 and has not funded their portion of the revolving credit agreements. At December 31, 2008, approximately $4 million and $11 million, respectively, of OGE Energy’s and the Company’s revolving credit agreements are not available as this portion was assigned to Lehman.

(B) Includes direct borrowings, outstanding commercial paper and letters of credit at December 31, 2008.

(C) This bank facility is available to back up OGE Energy’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2008, there was approximately $298.0 million in outstanding borrowings under this revolving credit agreement. There were no outstanding commercial paper borrowings at December 31, 2008.

(D) This bank facility is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2008, there were no outstanding borrowings under this revolving credit agreement and approximately $0.3 million supporting letters of credit. There were no outstanding commercial paper borrowings at December 31, 2008.

(E) In December 2006, OGE Energy and the Company amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for OGE Energy and $400 million for the Company. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods upon agreement of all banks participating in the revolving credit agreements. In November 2007, OGE Energy and the Company utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at maturity to convert the outstanding balance to a one-year term loan.

(F) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements.

OGE Energy’s and the Company’s ability to access the commercial paper market has been adversely impacted by the market turmoil since September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis.

However, in late 2008, OGE Energy’s and the Company’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, the Company repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. The Company intends to utilize commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreements and begin utilizing the commercial paper market when available. The Company also borrowed under the term loan agreements discussed below.

In addition to general market conditions, OGE Energy’s and the Company’s ability to access the commercial paper market could also be adversely impacted by a credit ratings downgrade. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the ratings of OGE Energy or the Company would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.

The Company had a commercial paper arrangement with Lehman, which filed for bankruptcy protection on September 15, 2008. On September 22, 2008, Barclays Plc purchased the investment banking and capital markets operations of Lehman and replaced Lehman as the commercial paper dealer in the Company’s commercial paper arrangement. Also, the Company has a commercial paper arrangement with Wachovia Bank, National Association, which merged with Wells Fargo & Company on December 31, 2008.

On September 26, 2008, the Company entered into a 10-day $300 million term loan agreement with Royal Bank of Scotland PLC (“RBS”). On September 29, 2008, after the Company purchased the entire partnership interest in the Redbud Facility, the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”) purchased their respective undivided interests in the Redbud Facility from the Company for approximately $417.5 million. After the closing of the sale of the undivided interests in the Redbud Facility, the Company used the $417.5 million in proceeds and repaid in full, on September 30, 2008, the $300 million borrowed from RBS and invested the remainder of the proceeds in short-term investments which were recorded as Cash and Cash Equivalents on the Company’s Balance Sheet.

On September 26, 2008, the Company entered into a $200 million term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC maturing March 26, 2010. This loan could be used for general corporate purposes and permitted acquisitions as defined in the loan agreement. On December 15, 2008, the Company repaid the outstanding $50.0 million balance and terminated this loan agreement.

Unlike OGE Energy, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2009 and ending December 31, 2010.

12.

Retirement Plans and Postretirement Benefit Plans

In September 2006, the FASB issued SFAS No. 158 which required an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements were effective for the year ended December 31, 2006 for the Company. Also, as a part of SFAS No. 158, an employer is required to measure the fair value of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to measure plan assets and benefit obligations at fair value in accordance with SFAS No. 157 as of the date of the employer’s fiscal year-end statement of financial position was effective for fiscal years ending after December 15, 2008. The Company adopted this additional provision of SFAS No. 158 effective December 31, 2008 which had no impact to the Company as its measurement date and its fiscal year-end statement of financial position were the same.

Defined Benefit Pension Plan

All eligible employees of the Company are covered by a non-contributory defined benefit pension plan sponsored by OGE Energy. For employees hired on or after February 1, 2000, the pension plan is a cash balance plan, under which OGE Energy annually will credit to the employee’s account an amount equal to five percent of the employee’s annual compensation plus accrued interest. Employees hired prior to February 1, 2000, will receive the greater of the cash balance benefit or a

benefit based primarily on years of service and the average of the five highest consecutive years of compensation during an employee’s last ten years prior to retirement, with reductions in benefits for each year prior to age 62 unless the employee’s age and years of credited service equal or exceed 80.

It is OGE Energy’s policy to fund the plan on a current basis based on the net periodic SFAS No. 87, “Employers’ Accounting for Pensions,” pension expense as determined by the Company’s actuarial consultants. Additional amounts may be contributed from time to time to increase the funded status of the plan. During both 2008 and 2007, OGE Energy made contributions to its pension plan of approximately $50.0 million of which approximately $47.0 million and $38.3 million, respectively, were the Company’s portion, to help ensure that the pension plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2009, OGE Energy may contribute up to $50.0 million to its pension plan, of which approximately $47.0 million is expected to be the Company’s portion. The expected contribution to the pension plan during 2009 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation or the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007, OGE Energy and the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. The Company did not record a pension settlement charge during 2008. The pension settlement charge and retirement restoration plan settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense or restoration retirement expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions)	OGE Energy	Company’s Portion (A)

Pension Settlement Charge:
2007	$ 16.7	$ 13.3

Retirement Restoration Plan Settlement Charge:
2007	$ 2.3	$ 0.1

(A) The Company’s Oklahoma jurisdictional portion of these charges were recorded as a regulatory asset (see Note 1 for a further discussion).

Pension Plan Costs and Assumptions

contributions, introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants.

Many of the changes enacted as part of the Pension Protection Act were required to be implemented as of the first plan year beginning in 2008. While OGE Energy generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. In order to be in compliance with the Pension Protection Act, the Company has implemented the following changes to its defined benefit pension plan and defined contribution plan, as applicable: (i) effective January 1, 2008, the Company’s defined benefit pension plan and defined contribution plans were amended to incorporate clarifying provisions and changes relating to the Pension Protection Act notice requirements and allow a non-spouse beneficiary to directly rollover an eligible distribution to an eligible individual retirement account (“IRA”) or to a Roth IRA; (ii) effective January 1, 2008, the Company’s defined benefit pension plan and defined contribution plans were amended to provide 100 percent vesting after completing three years of service; (iii) for the Company’s defined benefit pension plan, effective January 1, 2008, that plan was amended to incorporate the new Pension Protection Act applicable mortality table and applicable interest rate under Internal Revenue Code Section 417(e)(3) for determining the actuarial equivalent value of a benefit that is converted to a lump sum; (iv) for the Company’s defined contribution plan, effective January 1, 2008, that plan was amended to provide, in accordance with the Pension Protection Act that participants under age 55 may diversify amounts held in his/her TRASOP account out of the OGE Energy Corp Common Stock Fund into other investment funds; and (v) for the Company’s defined contribution plan, that plan was amended to implement an eligible automatic contribution arrangement and provide for a qualified default investment alternative consistent with the Department of Labor regulations. The Company has taken steps to ensure that its plans, as well as participants and outside administrators, are aware of the changes.

Plan Investments, Policies and Strategies

The pension plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, listed common stocks and corporate debt. The following table shows, by major category, the percentage of the fair value of the plan assets held at December 31, 2008 and 2007:

December 31	2008	2007
Equity securities	45 %	61 %
Debt securities	53 %	37 %
Other	2 %	2 %
Total	100 %	100 %

The pension plan assets are held in a trust which follows an investment policy and strategy designed to maximize the long-term investment returns of the trust at prudent risk levels. Common stocks are used as a hedge against moderate inflationary conditions, as well as for participation in normal economic times. Fixed income investments are utilized for high current income and as a hedge against deflation. OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of OGE Energy’s members and OGE Energy’s Employee Benefit Funds Management Committee (the “Investment Committee”).

The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for their respective portfolio. The table below shows the target asset allocation percentages for each major category of plan assets:

Asset Class	Target Allocation	Minimum	Maximum
Domestic Equity	30 %	--- %	60 %
Domestic Mid-Cap Equity	10 %	--- %	10 %
Domestic Small-Cap Equity	10 %	--- %	10 %
International Equity	10 %	--- %	10 %
Fixed Income Domestic	38 %	30 %	70 %
Cash	2 %	--- %	5 %

The portfolio is rebalanced on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust’s exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors’ investment style. The goal of the trust is to provide a rate of return consistently from three to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class	Comparative Benchmark(s)
Fixed Income	Lehman Aggregate Index
Equity Index	S&P 500 Index
Value Equity	Russell 1000 Value Index – Short-term
	S&P 500 Index – Long-term
Growth Equity	Russell 1000 Growth Index – Short-term
	S&P 500 Index – Long-term
Mid-Cap Equity	S&P 400 Midcap Index
Small-Cap Equity	Russell 2000 Index
International Equity	Morgan Stanley Capital International Europe, Australia and Far East Index

The fixed income manager is expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody’s Investors Service (“Moody’s”), Standard & Poor’s or Fitch Ratings. The portfolio may invest up to ten percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of OGE Energy’s equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the S&P 400 Midcap Index, small dividend yield, return on equity at or near the S&P 400 Midcap Index and earnings per share growth rate at or near the S&P 400 Midcap Index. The domestic small-capitalization equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International Europe, Australia and the Far East Index (“EAFE”) is the benchmark for comparative performance purposes. The EAFE Index is a market value weighted index comprised of over 1,000 companies traded on the stock markets of Europe, Australia, New Zealand and the Far East. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (ten percent for mid-cap and small-cap equity managers) after accounting for price appreciation. A minimum of 95 percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Options or financial futures may not be purchased unless prior approval of the Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of OGE Energy’s equity, debt or other

securities is prohibited. The purchase of equity or debt issues of the portfolio manager’s organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

Restoration of Retirement Income Plan

OGE Energy provides a restoration of retirement income plan to those participants in OGE Energy’s pension plan whose benefits are subject to certain limitations under the Internal Revenue Code (the “Code”). The benefits payable under this restoration of retirement income plan are equivalent to the amounts that would have been payable under the pension plan but for these limitations. The restoration of retirement income plan is intended to be an unfunded plan.

The Company expects to pay benefits related to its pension plan and restoration of retirement income plan of approximately $48.5 million in 2009, $48.7 million in 2010, $49.6 million in 2011, $51.9 million in 2012, $51.3 million in 2013 and an aggregate of $215.0 million in years 2014 to 2018. These expected benefits are based on the same assumptions used to measure the Company’s benefit obligation at the end of the year and include benefits attributable to estimated future employee service.

Postretirement Benefit Plans

In addition to providing pension benefits, OGE Energy provides certain medical and life insurance benefits for eligible retired members (“postretirement benefits”). Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained age 55 with ten years of vesting service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Prior to January 1, 2008, all regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with five years of vesting service at the time of retirement are entitled to postretirement life insurance benefits. Effective January 1, 2008, all regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with three years of vesting service at the time of retirement are entitled to postretirement life insurance benefits. Eligible retirees must contribute such amount as OGE Energy specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. The Company charges to expense the SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions,” costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

At December 31, 2008, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $191.9 million and $55.1 million, respectively, for an underfunded status of approximately $136.8 million. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.

At December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $179.2 million and $76.0 million, respectively, for an underfunded status of approximately $103.2 million. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 9.0 percent in 2009 with the rates decreasing in subsequent years by one percentage point per year through 2012. A one-percentage point change in the assumed health care cost trend rate would have the following effects:

ONE-PERCENTAGE POINT INCREASE
Year ended December 31 (In millions)	2008	2007	2006
Effect on aggregate of the service and interest cost components	$ 1.7	$ 1.8	$ 1.7
Effect on accumulated postretirement benefit obligations	22.3	21.4	23.4

ONE-PERCENTAGE POINT DECREASE
Year ended December 31 (In millions)	2008	2007	2006
Effect on aggregate of the service and interest cost components	$ 1.4	$ 1.5	$ 1.4
Effect on accumulated postretirement benefit obligations	18.6	17.8	19.3

Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. Management expects that the accumulated plan benefit obligation (“APBO”) for OGE Energy with respect to its postretirement medical plan will be reduced by approximately $70.9 million as a result of savings to OGE Energy with respect to its postretirement medical plan resulting from the Medicare Act provided subsidy, which will reduce OGE Energy’s costs for its postretirement medical plan by approximately $5.6 million annually. The $5.6 million in annual savings is comprised of a reduction of approximately $2.4 million from amortization of the $70.9 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $2.6 million and a reduction in the service cost due to the subsidy of approximately $0.6 million.

The Company expects to pay gross benefits payments related to its postretirement benefit plans, including prescription drug benefits, of approximately $11.6 million in 2009, $12.5 million in 2010, $13.5 million in 2011, $14.2 million in 2012, $14.9 million in 2013 and an aggregate of $81.4 million in years 2014 to 2018. The Company expects to receive Federal subsidy receipts provided by the Medicare Act of approximately $1.5 million in 2009, $1.6 million in 2010, $1.8 million in 2011, $1.9 million in 2012, $2.1 million in 2013 and an aggregate of $12.2 million in years 2014 to 2018. OGE Energy received approximately $0.8 million in Federal subsidy receipts in 2008.

Obligations and Funded Status

The following table presents the status of the Company’s portion of OGE Energy’s pension plan, the restoration of retirement income plan and the postretirement benefit plans for 2008 and 2007. The Company’s portion of the benefit obligation for OGE Energy’s pension plan and the restoration of retirement income plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for the pension plan and the restoration of retirement income plan at December 31, 2008 was approximately $391.7 million and $0.8 million, respectively. The accumulated benefit obligation for the pension plan and the restoration of retirement income plan at December 31, 2007 was approximately $373.8 million and $0.8 million, respectively. The details of the funded status of the pension plan, the restoration of retirement income plan and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:

			Restoration of Retirement			Postretirement
	Pension Plan		Income Plan			Benefit Plans
December 31 (In millions)	2008	2007	2008	2007		2008	2007

Change in Benefit Obligation
Beginning obligations	$ (413.6)	$ (465.2)	$ (0.8)	$ (0.4)		$ (179.2)	$ (188.0)
Service cost	(12.4)	(13.8)	---	---		(2.3)	(2.7)
Interest cost	(24.9)	(25.6)	(0.1)	---		(11.1)	(10.4)
Plan changes	---	12.6	---	(0.1)		---	---
Participants’ contributions	---	---	---	---		(4.9)	(4.5)
Actuarial gains (losses)	(15.3)	13.2	(0.5)	(0.5)		(6.4)	12.7
Benefits paid	33.6	65.2	0.3	0.2		12.0	13.7
Ending obligations	(432.6)	(413.6)	(1.1)	(0.8)		(191.9)	(179.2)

Change in Plans’ Assets
Beginning fair value	400.7	410.1	---		---	76.0	71.7
Actual return on plans’ assets	(104.9)	17.5	---		---	(18.7)	5.4
Employer contributions	47.0	38.3	0.3		0.2	4.9	8.1
Participants’ contributions	---	---	---		---	4.9	4.5
Benefits paid	(33.6)	(65.2)	(0.3)		(0.2)	(12.0)	(13.7)
Ending fair value	309.2	400.7	---		---	55.1	76.0
Funded status at end of year	$ (123.4)	$ (12.9)	$ (1.1)		$ (0.8)	$ (136.8)	$ (103.2)

Net Periodic Benefit Cost

				Restoration of Retirement			Postretirement
	Pension Plan			Income Plan			Benefit Plans
Year ended December 31
(In millions)	2008	2007	2006	2008	2007	2006	2008	2007	2006
Service cost	$ 12.4	$ 13.8	$ 13.4	$ ---	$ ---	$ ---	$ 2.3	$ 2.7	$ 2.6
Interest cost	24.9	25.6	24.7	0.1	---	---	11.1	10.4	10.0
Return on plan assets	(34.3)	(34.5)	(30.4)	---	---	---	(6.3)	(5.7)	(5.5)
Amortization of transition
obligation	---	---	---	---	---	---	2.5	2.5	2.5
Amortization of net loss	7.4	8.4	13.4	0.1	---	---	3.5	5.5	7.6
Amortization of recognized
prior service cost	1.1	4.5	4.6	0.1	0.1	0.1	1.5	1.5	1.5
Settlement	---	13.3	13.3	---	0.1	---	---	---	---
Net periodic benefit cost (A)	$ 11.5	$ 31.1	$ 39.0	$ 0.3	$ 0.2	$ 0.1	$ 14.6	$ 16.9	$ 18.7

(A) In addition to the $11.8 million and $31.3 million in SFAS No. 87 net periodic benefit cost recognized in 2008 and 2007, respectively, the Company also recognized an expense of approximately $7.5 million and a gain of approximately $8.3 million, respectively, related to the reversal of a portion of the regulatory asset identified as Deferred Pension Plan Expenses (see Note 1). The capitalized portion of the net periodic pension benefit cost was approximately $3.6 million, $5.2 million and $7.2 million at December 31, 2008, 2007 and 2006, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $4.2 million, $4.5 million and $5.6 million at December 31, 2008, 2007 and 2006, respectively.

Rate Assumptions

	Pension Plan and			Postretirement
	Restoration of Retirement Income Plan			Benefit Plans
Year ended December 31	2008	2007	2006	2008	2007	2006
Discount rate	6.25%	6.25%	5.75%	6.25%	6.25%	5.75%
Rate of return on plans’ assets	8.50%	8.50%	8.50%	8.50%	8.50%	8.50%
Compensation increases	4.50%	4.50%	4.50%	4.50%	4.50%	4.50%
Assumed health care cost trend:
Initial trend	N/A	N/A	N/A	9.00%	9.00%	9.00%
Ultimate trend rate	N/A	N/A	N/A	4.50%	4.50%	4.50%
Ultimate trend year	N/A	N/A	N/A	2014	2013	2012

N/A - not applicable

The overall expected rate of return on plan assets assumption remained at 8.50 percent in 2007 and 2008 in determining net periodic benefit cost. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the pension plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans’ current and expected asset allocation.

Post-Employment Benefit Plan

Disabled employees receiving benefits from OGE Energy’s Group Long-Term Disability Plan are entitled to continue participating in the Company’s Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in OGE Energy’s Group Long-Term Disability Plan and their dependents, as defined in OGE Energy’s Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from OGE Energy’s Group Long-Term Disability Plan due to death, recovery from disability, or eligibility

for retiree medical benefits. The Company’s post-employment benefit obligation was approximately $1.6 million and $1.3 million at December 31, 2008 and 2007, respectively.

Defined Contribution Plan

OGE Energy provides a defined contribution savings plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the plan after completing one year of service as defined in the plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the plan, for that pay period. Contributions of the first six percent of compensation are called “Regular Contributions” and any contributions over six percent of compensation are called “Supplemental Contributions.” Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as “Catch-Up Contributions,” subject to the limitations of the Code. OGE Energy contributes to the plan each pay period on behalf of each participant an amount equal to 50 percent of the participant’s Regular Contributions for participants whose employment or re-employment date, as defined in the plan, occurred before February 1, 2000 and who have less than 20 years of service, as defined in the plan, and an amount equal to 75 percent of the participant’s Regular Contributions for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service. For participants whose employment or re-employment date occurred on or after February 1, 2000, OGE Energy contributes 100 percent of the Regular Contributions deposited during such pay period by such participant. No OGE Energy contributions are made with respect to a participant’s Supplemental Contributions, Catch-Up Contributions, rollover contributions, or with respect to a participant’s Regular Contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. OGE Energy’s contribution which is initially allocated for investment to the OGE Energy Common Stock Fund may be made in shares of OGE Energy’s common stock or in cash which is used to invest in OGE Energy’s common stock. Once made, OGE Energy’s contribution may be reallocated, on any business day, by participants to other available investment options. The Company contributed approximately $5.1 million, $4.7 million and $4.2 million during 2008, 2007 and 2006 respectively, to the defined contribution plan.

Deferred Compensation Plan

OGE Energy provides a deferred compensation plan. The plan’s primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees’ defined contribution plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of bonus awards; or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the defined contribution plan with such deferrals to start when maximum deferrals to the qualified defined contribution plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors’ meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to provide for the match that would have been made under the defined contribution plan had such deferrals been made under that plan without regard to the statutory limitations on elective deferrals and matching contributions applicable to the defined contribution plan. In addition, the Benefits Committee may award discretionary employer contribution credits to a participant under the plan. OGE Energy accounts for the contributions related to the Company’s executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company’s directors in this plan as Other Deferred Credits and Other Liabilities in the Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in OGE Energy’s Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the liability under the plan is accounted for as Other Expense in OGE Energy’s Consolidated Statements of Income.

Supplemental Executive Retirement Plan

OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy’s Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy’s pension plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the Code.

13.

Commitments and Contingencies

Operating Lease Obligations

Future minimum payments for the noncancellable operating lease for railcars are as follows:

						2014 and
Year ended December 31 (In millions)	2009	2010	2011	2012	2013	Beyond

Railcars	$ 3.9	$ 3.8	$ 38.0	$ ---	$ ---	$ ---

Payments for operating lease obligations were approximately $3.9 million, $3.9 million and $4.2 million in 2008, 2007 and 2006, respectively.

Railcar Lease Agreement

At December 31, 2007, the Company had a noncancellable operating lease with purchase options, covering 1,409 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through the Company’s tariffs and fuel adjustment clauses. On December 29, 2005, the Company entered into a new lease agreement for railcars effective February 1, 2006 with a new lessor as described below. In April 2008, the Company amended its contract to add 55 new railcars for approximately $3.5 million. At the end of the new lease term, which is January 31, 2011, the Company has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If the Company chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, the Company would be responsible for the difference in those values up to a maximum of approximately $31.5 million. In mid-February 2009, the Company expects to enter into a new short-term lease agreement to add 270 new railcars for approximately $1.2 million to satisfy the requirements of its new coal transportation contracts with BNSF Railway and Union Pacific as discussed below. The expiration dates of the lease agreement are expected to be: (i) six months from the effective date of the lease agreement for 135 cars and (ii) one year from the effective date of the lease agreement for the other 135 cars. The Company is also required to maintain the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.

Coal Transportation Contracts

The Company has transportation contracts for the transportation of coal to its coal-fired power plants. The Company’s transportation contracts expired on December 31, 2008. On December 19, 2008, the Company entered into a new rail transportation agreement with the BNSF Railway for the movement of coal to the Company’s Sooner power plant. The Company has also filed a complaint at the Surface Transportation Board (“STB”) requesting the establishment of reasonable rates, practices and service terms for the transportation of coal from Union Pacific served mines in the southern Powder River Basin, Wyoming to the Company’s Muskogee power plant. The timing of the completion of this proceeding is uncertain at this time. The effect of the new BNSF Railway agreement and the anticipated rail rate prescription from the STB for rail transportation to the Company’s Sooner and Muskogee power plants is expected to cause an approximate 50 percent increase in the Company’s delivered coal prices.

Public Utility Regulatory Policy Act of 1978

At December 31, 2008, the Company has agreements with two qualifying cogeneration facilities (“QF”) having terms of 15 to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978 (“PURPA”). Stated generally, PURPA and the regulations thereunder promulgated by the FERC require the Company to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by the Company was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by the Company; the other is a capacity charge, which the Company must pay the QF for having the capacity available. However, if no electrical power is made available to the Company for a period of time (generally three months), the Company’s obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the AES-Shady Point, Inc. (“AES”) QF contract for 320 MWs, the Company purchases 100 percent of the electricity generated by the QF. In addition, effective September 1, 2004, the Company entered into a new 15-year power purchase agreement for

120 MWs with Powersmith Cogeneration Project, L.P. (“PowerSmith”) in which the Company purchases 100 percent of electricity generated by PowerSmith.

During 2008, 2007 and 2006, the Company made total payments to cogenerators of approximately $152.8 million, $156.8 million and $162.6 million, respectively, of which approximately $84.4 million, $88.9 million and $94.9 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Goods Sold. The future minimum capacity payments under the contracts are approximately: 2009 – $86.8 million, 2010 – $85.0 million, 2011 – $83.1 million, 2012 – $81.0 million and 2013 – $81.0 million.

Fuel Minimum Purchase Commitments

The Company purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $215.1 million, $190.2 million and $195.1 million for the years ended December 31, 2008, 2007 and 2006, respectively. The Company has entered into purchase commitments of necessary fuel supplies of approximately: 2009 – $320.7 million, 2010 – $114.1 million, 2011 – $65.2 million, 2012 – $3.9 million, 2013 – $3.9 million and 2014 and Beyond – $19.5 million.

Natural Gas Units

In August 2008, the Company issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2008 through March 2009, which accounted for approximately 15 percent of its projected 2009 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2009. Additional gas supplies to fulfill the Company’s remaining 2009 natural gas requirements will be acquired through additional RFPs in early to mid-2009, along with monthly and daily purchases, all of which are expected to be made at market prices.

Natural Gas Measurement Cases

United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that the Company and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, OGE Energy and the Enogex parties filed a notice of its intent to file a separate response brief, which OGE Energy filed on January 11, 2008. Oral arguments were made to the Tenth Circuit on September 25, 2008. No ruling was made on the oral arguments and the court took the case under advisment. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of OGE Energy’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

Franchise Fee Lawsuit

On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes the Company to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on December 4, 2008. The OCC expects to hear arguments for a motion to dismiss on March 26, 2009. The Company believes that this case is without merit.

Oxley Litigation

The Company has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma. This case has been pending for more than 11 years. The plaintiffs’ alleged that the Company breached the terms of contracts covering several wells by failing to purchase gas from the plaintiff in amounts set forth in the contracts. The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described

below. In 2001, the Company agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, the Company will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The Company expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, The Company believes that this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations.

Environmental Laws and Regulations

Environmental regulation can increase the cost of planning, design, initial installation and operation of the Company’s facilities. Historically, the Company’s total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. The Company believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards may increase the cost of conducting business.

Approximately $1.0 million and $31.5 million, respectively of the Company’s capital expenditures budgeted for 2009 and 2010 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 $35.7 million during 2009 as compared to approximately $37.1 million in 2008. 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.

Air

On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule. Various petitions and appeals related to this decision have been made and are not yet resolved. On February 6, 2009, the EPA filed a motion to dismiss their earlier request for the U.S. Supreme Court to review the 2008 decision. Industry interests are still seeking the U.S. Supreme Court review in the case. The EPA has stated that it intends to draft mercury rules under the Federal Clean Air Act. The Company cannot predict the outcome of the Federal litigation at this time. Until the rule was vacated, the CAMR required mercury monitoring to begin in 2009. Accordingly, the Company installed mercury monitoring equipment on all five of its coal units. The cost of the monitoring equipment was approximately $5.0 million in 2007 and approximately $0.4 million in 2008. Because the CAMR litigation is ongoing, the cost to install mercury controls is uncertain at this time but may be significant, particularly if the EPA develops more stringent requirements. Because of the uncertainty caused by the litigation regarding the CAMR, the promulgation of an Oklahoma rule that would apply to existing facilities has been delayed. The Company will continue to participate in the state rule making process.

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the regulation. However, Oklahoma’s impact on parks in other states must

also be evaluated. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. The State of Oklahoma has joined with eight other central states to address these visibility impacts.

In September 2005, the Oklahoma Department of Environmental Quality (“ODEQ”) informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have “Best Available Retrofit Technology (“BART”) eligible sources” (sources built between 1962 and 1977). For the Company, these include various generating units at various generating stations. Regulations, however, allow an owner or operator of a BART-eligible source to request and obtain a waiver from BART if modeling shows no significant impact on visibility in nearby Class I areas. Based on this modeling, the ODEQ made a preliminary determination to accept an application for a waiver for the Horseshoe Lake generating station. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan.

The modeling did not support waivers for the affected units at the Seminole, Muskogee and Sooner generating stations. The Company submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, the Company submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants will achieve overall greater visibility improvement than BART in the affected Class I areas and the alternative plan extends the timeline for compliance to 2018. The cost for this alternative compliance plan, including the BART compliance plan for the Seminole power plant (the alternative compliance plan and the BART compliance plan are collectively referred to herein as the “alternative plan”), was estimated at approximately $470 million in March 2007. The alternative plan included installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan was subject to approval by the ODEQ and the EPA. The EPA provided comments to the ODEQ on the Company’s alternative plan. On November 16, 2007, the ODEQ notified the Company that additional analysis would be required before the Company alternative plan could be accepted. On May 30, 2008, the Company filed the results with the ODEQ for the affected generating units as well as withdrawing its alternative plan filed in March 2007. In the May 30, 2008 filing, the Company indicated its intention to install low NOX combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. The Company believes that these control measures will achieve visibility improvements in a cost-effective manner. The Company did not propose the installation of scrubbers at its four coal-fired generating units because the Company concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. The Company previously reported an expectation that a compliance plan would be approved by the EPA by December 31, 2008; however, submission of the overall compliance plan by the ODEQ (which will include the Company’s compliance plan previously submitted to the ODEQ) has been delayed and the current timing of the EPA approval cannot be reasonably predicted. In a letter dated November 4, 2008, the EPA notified the ODEQ that they had completed their review of BART applications for all affected sources in Oklahoma, which included the Company. The EPA did not approve or disapprove the applications, however, additional information was requested from the ODEQ by the EPA regarding the Company’s plan. The Company cannot predict what action the EPA or the ODEQ will take in response to the Company’s May 30, 2008 filing or the November 4, 2008 letter from the EPA. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. The Company expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from the Company’s retail customers under House Bill 1910, which was enacted into law in May 2005.

The original deadline for the ODEQ to submit a state implementation plan for regional haze that includes final BART determinations was December 17, 2007. The ODEQ did not meet this deadline. On January 15, 2009, the EPA published a rule that gives the ODEQ two years to complete the state implementation plan. If the ODEQ fails to meet this deadline, the EPA can issue a Federal implementation plan.

The 1990 Clean Air Act includes an acid rain program to reduce sulfur dioxide (“SO2”) emissions. Reductions were obtained through a program of emission (release) allowances issued by the EPA to power plants covered by the acid rain program. Each allowance is worth one ton of SO2 released from the chimney. Plants may only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements in Phase II of the acid rain program. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2008, the Company’s SO2 emissions were below the allowable limits.

The EPA allocated SO2 allowances to the Company starting in 2000 and the Company started banking allowances in 2001. The Company sold no banked allowances in 2008. Also, during 2008, the Company received proceeds of approximately $0.4 million from the annual EPA spot (year 2008) and seven-year advance (year 2015) allowance auctions that were held in March 2008.

With respect to the NOX regulations of the acid rain program, the Company committed to meeting a 0.45 lbs/million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a result, the Company was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. The regulations required that the Company achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers which began in 2008. The Company’s average NOX emissions from its coal-fired boilers for 2008 were approximately 0.32 lbs/MMBtu. It is expected that NOX emissions will be further reduced to 0.15 lbs/MMBtu by 2016 if the regional haze compliance plan discussed above is approved by the EPA. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are impacting the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma becomes non-attainment with the fine particulate standard. Any of these scenarios would likely require significant capital and operating expenditures.

On September 21, 2006, the EPA lowered the 24-hour fine particulate ambient standard while retaining the annual standard at its current level and promulgated a new standard for inhalable coarse particulates. Based on past monitoring data, it appears that Oklahoma may be able to remain in attainment with these standards. However if parts of Oklahoma do become “non-attainment”, reductions in emissions from the Company’s coal-fired boilers could be required which may result in significant capital and operating expenditures.

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone of 0.08 parts per million (“PPM”). In March 2008, the EPA lowered the ambient primary and secondary standards to 0.075 PPM. Oklahoma has until March 2009 to designate any areas of non-attainment within the state, based on ozone levels in 2006 through 2008. Following the state’s designation, the EPA is expected to determine a final designation by March 2010. States will be required to meet the ambient standards between 2013 and 2030, with deadlines depending on the severity of their ozone level. Oklahoma City and Tulsa are the most likely areas to be designated non-attainment in Oklahoma. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.

On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Clean Air Act as a result of the adoption of the revised ambient ozone and fine particle standards. Failure to submit these implementation plans began a two-year timeframe, starting on May 25, 2005, during which states must submit a demonstration to the EPA that they do not affect air quality in downwind states. The demonstration was properly submitted by the state to the EPA on May 7, 2007, and additional information was submitted by the state to EPA on December 5, 2007. Assuming the state implementation plan is approved as submitted, there should be no significant adverse impact to the Company as a result of the April 25, 2005 finding. The date of EPA approval of Oklahoma’s demonstration is currently unknown.

In July 2008, the Company received a request for information from the EPA regarding Clean Air Act compliance at the Company’s Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Clean Air Act’s new source review process. The Company believes it has acted in full compliance with the Clean Air Act and new source review process and is cooperating with the EPA. On August 28, 2008, the Company submitted information to the EPA and submitted additional information on October 31, 2008. The Company cannot predict what, if any, further actions the EPA may take with respect to this matter.

At December 31, 2008, the Company had received Title V permits for all of its generating stations and intends to continue to renew these permits as necessary. In January 2008, the ODEQ proposed fee increases of approximately 28 percent for Title V sources and 13 percent for minor sources. These fee increases were approved and became effective July 1, 2008. Air permit fees for the Company’s generating stations were approximately $0.8 million in 2008.

In addition to the requirements related to emissions of SO2, NOX and mercury discussed above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air

Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.

On the legislative front, in June 2005, the U.S. Senate adopted a resolution declaring that mandatory reductions in greenhouse gases are needed. Despite executive branch opposition to any mandatory requirements, several bills that would cap or tax greenhouse gases from electric utilities are being considered by Congress, and the concept of such regulation has received support from the majority leadership in both the U.S. Senate and U.S. House of Representatives.

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and Federal action on climate change issues. The Company reports quarterly its carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Waste

The Company has sought and will continue to seek, new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2008, the Company obtained refunds of approximately $2.2 million from its recycling efforts. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

Water

The Company received two Oklahoma Pollutant Discharge Elimination System (“OPDES”) renewal permits in February 2008 from the state of Oklahoma. The Company filed an OPDES renewal application with the state of Oklahoma on August 4, 2008 for its Seminole power plant and received a draft permit for review on January 9, 2009. The Company is currently reviewing this draft permit to determine if it is reasonable in its requirements and allows operational flexibility.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA Section 316(b) rules for existing facilities became effective July 23, 2004. On January 25, 2007, a Federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the state of Oklahoma required a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility. On January 7, 2008, the Company submitted the requested studies for its facilities. Additionally, on April 14, 2008, the U.S. Supreme Court granted writs of certiorari and will review the question of whether the Section 316(b) rules authorize the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. It is not clear what changes, if any, the EPA will ultimately make to the Section 316(b) rules or how those changes may affect the Company. Depending on the ultimate analysis and final determinations regarding the Section 316(b) rules and the comprehensive demonstration studies, capital and/or operating costs may increase at any affected Company generating facility. The Company expects a ruling from the U.S. Supreme Court on the Section 316(b) rules in mid-2009.

Other

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Financial Statements. Except as otherwise stated above, in Note 14 below and in Item 3 of this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

14.

Rate Matters and Regulation

Regulation and Rates

Completed Regulatory Matters

Acquisition of Redbud Power Plant

On January 21, 2008, the Company entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which were indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, the Company agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which owned the Redbud Facility for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.

In connection with the Purchase and Sale Agreement, the Company also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the OMPA and the GRDA, pursuant to which the Company agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which the Company, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and the Company will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.

On September 16, 2008, the FERC issued an order approving the Redbud acquisition. In the order, the FERC concluded that the Redbud acquisition could harm horizontal competition by increasing market concentration. However, the FERC concluded that, since the Company had committed to construct specific upgrades on the system, these would be adequate mitigation measures. Accordingly, the FERC conditioned its approval of the Redbud acquisition on the Company’s completion of these upgrades. The Company is required to file quarterly updates describing the progress of the transmission upgrades, the first of which was filed December 16, 2008. The Company also must notify the FERC of any change in circumstances regarding these projects. During the approximately 27-month period required to construct the transmission upgrades, the FERC did not require any interim mitigation beyond the limits of the Company’s market-based rate authority and the SPP market monitoring programs currently in place. In addition, the FERC found that the proposed transaction would have no adverse effects on vertical market power, on wholesale rates, or on state or Federal regulation. The FERC also determined that the transaction presented no cross-subsidy concerns. Finally, the FERC rejected various arguments raised by AES that sought to expand the

scope of the FERC proceeding or to impose additional conditions on the Redbud acquisition. On September 24, 2008, the OCC issued an order approving the Redbud acquisition. The Company closed on the Redbud acquisition on September 29, 2008. The Company implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes.

Cancelled Red Rock Power Plant and Storm Cost Recovery Rider

On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, the Company requested authorization to sell approximately $14.7 million of its SO2 allowances and to retain 100 percent of the proceeds to offset the $14.7 million of Red Rock costs. Under a prior order of the OCC, 90 percent of the proceeds from sales of SO2 allowances were to be credited to ratepayers. Any portion of the $14.7 million of deferred costs that the OCC did not approve for recovery by the Company was to be expensed. In its response to the Company’s Red Rock cost recovery application, the OCC Staff recommended, among other things, that the Company sell SO2 allowances and retain 100 percent of the proceeds from the sale to be used to offset the Company’s December 2007 ice storm costs. These ice storm costs were included as part of the regulatory asset balance of approximately $35.9 million at December 31, 2007 (see Note 1), in accordance with a prior order of the OCC, pending recovery in a future rate case. On June 27, 2008, the Company filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, the Company will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with the Company’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date the Company begins to recover the regulatory asset through the base rates established in the Company’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in the Company’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover the Company’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess SO2 allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by the Company and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, the Company wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Financial Statements.

Renewable Energy Filing

Under the terms of the settlement agreement, the parties agreed that the Company will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and AFUDC when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million the Company be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above. On February 2, 2009, the Company received SPP approval to begin construction of the transmission line and the associated Woodward Extra High Voltage substation.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2006

The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2007, the OCC Staff filed an application for a prudence review of the Company’s 2006 fuel adjustment clause. In September 2008, the OCC issued an order approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2006.

Pending Regulatory Matters

FERC Formula Rate Filing

On November 30, 2007, the Company made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on the Company’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of the Company’s filing. The Company filed an answer to the OMPA’s protest on January 7, 2008. On January 31, 2008, the FERC issued an order (i) conditionally accepting the rates; (ii) suspending the effectiveness of such rates for five months, to be effective July 1, 2008, subject to refund; (iii) establishing hearing and settlement judge procedures; and (iv) directing the Company to make a compliance filing. In July 2008, rates were implemented in an annual amount of approximately $2.4 million, subject to refund. Several settlement conferences have been held with the most recent being on November 17 and 18, 2008. Since the November 17 and 18, 2008 settlement conferences, the parties have continued to engage in settlement discussions.

Arkansas Rate Case Filing

2008 Storm Cost Filing

On October 30, 2008, the Company filed an application with the APSC requesting authority to defer its 2008 storm costs that exceed the amount recovered in base rates. The application also requests the APSC to provide for recovery of the deferred 2008 storm costs in the Company’s pending rate case. On December 19, 2008, the APSC issued an order authorizing the Company to defer approximately $0.6 million in 2008 for incremental storm costs in excess of the amount included in the Company’s rates. The Company was also authorized to seek recovery in its pending rate case but was not guaranteed recovery. At December 31, 2008, these incremental storm costs were approximately $0.6 million, which has been recorded as a regulatory asset (see Note 1).

2009 Oklahoma Rate Case Filing

million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest.

System Hardening Filing

In December 2007, a major ice storm affected the Company’s service territory which resulted in a large number of customer outages. The OCC requested its Staff to review and determine if a rulemaking was warranted. The OCC Staff issued numerous data requests and is in the process of determining if other regulatory jurisdictions have policies or rules requiring that electric transmission and distribution lines be placed underground. The OCC Staff also surveyed customers. On June 30, 2008, the OCC Staff submitted a report entitled, “Inquiry into Undergrounding Electric Facilities in the State of Oklahoma.” The Company formed a plan to place facilities underground (sometimes referred to as system hardening) with capital expenditures of approximately $115 million over five years for underground facilities, as well as $10 million annually for enhanced vegetation management. On December 2, 2008, the Company filed an application with the OCC requesting approval of it proposed system hardening plan with a recovery rider. On February 5, 2009, a procedural schedule was set in this matter with a hearing scheduled for March 25, 2009. The Company expects to receive an order from the OCC in the second quarter of 2009, with a targeted implementation date for the program and rider in the third quarter of 2009.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2007

The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2008, the OCC Staff filed an application for a prudence review of the Company’s 2007 fuel adjustment clause. The Company is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, the Company requested and was granted an extension to file the MFRs by January 16, 2009, on which date the MFRs were submitted by the Company. A procedural schedule has not been established in this matter.

Security Enhancements

On January 15, 2009, the Company filed an application with the OCC to amend its security plan. The Company is seeking approval of new security projects and cost recovery through the previously authorized security rider. The annual revenue requirement is approximately $0.9 million. The Company expects to receive an order from the OCC in the third quarter of 2009. A procedural schedule has not been established in this matter.

Southwest Power Pool Transmission/Substation Project

In January 2009, the Company received notification from the SPP to begin construction on approximately 50 miles of new 345kV transmission line and certain substation upgrades at the Company’s Sunnyside substation, among other projects. The line will extend from the Company’s Sunnyside substation near Ardmore, Oklahoma, to a point approximately one-half of the distance to the Hugo substation owned by the Western Farmers Electric Cooperative near Hugo, Oklahoma. The line and substation improvements are estimated to cost approximately $96 million. The Company intends to begin preliminary line routing and acquisition of rights-of-way in early 2009. When construction is completed, which is expected in April 2012, the SPP will allocate a portion of the annual revenue requirement to Company customers according to the base-plan funding mechanism as provided in the SPP tariff for application to such improvements.

Market-Based Rate Authority

On December 22, 2003, the Company and OERI filed a triennial market power update based on the supply margin assessment test. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address the new interim tests. The Company and OERI submitted a compliance filing to the FERC on February 7, 2005 that applied the interim tests to the Company and OERI. In the compliance filing, the Company and OERI passed the pivotal supplier screen but did not pass the market share screen in the Company’s control area. The Company and OERI provided an explanation as to why their failure of the market share screen in the Company’s control area should not be viewed as an indication that they can exercise generation market power.

On June 7, 2005, the FERC issued an order on the Company’s and OERI’s market-based rate filing. Because the Company and OERI failed the market share screen for the Company’s control area, the FERC established hearing procedures to investigate whether the Company and OERI may continue to sell power at market-based rates in the Company’s control area. The order established a rebuttable presumption that the Company and OERI have the ability to exercise market power in the Company’s control area. The Company and OERI were requested to provide additional information that demonstrates to the

FERC that they cannot exercise market power in the first-tier markets as well. However, the order conditionally allows the Company and OERI to sell power in first-tier markets subject to the Company and OERI providing additional information that clearly shows that they pass the market share screen for the first-tier markets. The Company and OERI provided that additional information on July 7, 2005. On August 8, 2005, the Company and OERI informed the FERC that they will: (i) adopt the FERC default rate mechanism for sales of one week or less to loads that sink in the Company’s control area; and (ii) commit not to enter into any sales with a duration of between one week and one year to loads that sink in the Company’s control area. The Company and OERI also informed the FERC that any new agreements for long-term sales (one year or longer in duration) to loads that sink in the Company’s control area will be filed with the FERC and that the Company and OERI will not make such sales under their respective market-based rate tariffs. On January 20, 2006, the FERC issued a Notice of Institution of Proceeding and Refund Effective Date for the purpose of establishing the date from which any subsequent market-based sales would be subject to refund in the event the FERC concludes after investigation that the rates for such sales are not just and reasonable. The refund effective date was March 27, 2006.

On March 21, 2006, the FERC issued an order conditionally accepting the Company’s and OERI’s proposal to mitigate the presumption of market power in the Company’s control area. First, the FERC accepted the additional information related to first-tier markets submitted by the Company and OERI, and concluded that the Company and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the Company’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company’s control area (instead of only to sales sinking to load within the Company’s control area). On April 20, 2006, the Company submitted: (i) a compliance filing containing the specified revisions to the Company’s market-based rate tariffs and the new cost-based rate tariff; and (ii) a request for rehearing asking the FERC to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the FERC issued a tolling order that effectively provided the FERC additional time to consider the April 20, 2006 rehearing request. On July 25, 2006 and August 25, 2006, pursuant to a FERC March 20, 2006 order, the Company and OERI filed revisions to their market-based rate tariffs to allow them to sell energy imbalance service into the wholesale markets administered by the SPP at market-based rates. On April 4, 2008, the FERC rejected the Company’s April 20, 2006 request for rehearing and approved in part and rejected in part the Company’s April 20, 2006 compliance filing. The April 4, 2008 order directed the Company to evaluate whether any refunds are required to comply with the April 4, 2008 order and to: (i) make any necessary refunds, or (ii) file a report with the FERC stating that no refunds are due. Refunds would apply only to new market-based sales made or new market-based contracts entered into after the March 21, 2006 order. The April 4, 2008 order also directed the Company to make another compliance filing to revise its market-based rate tariffs to adhere to the FERC’s June 21, 2007 final rule that revised standards for market-based rate sales of electric energy, capacity and ancillary services. On May 5, 2008, the Company submitted a compliance report stating that no refunds were due. On May 30, 2008, the Company and OERI submitted to the FERC a change in status report notifying the FERC that the Company had entered into a contract with Westar Energy under which the Company agreed to purchase 300 MWs of capacity and energy for the periods from May 1, 2008 through August 31, 2008, and from May 1, 2009 through August 31, 2009. The Company and OERI explained that this purchase agreement was not material to the FERC’s grant of market-based rate status to the Company and OERI. The FERC has not yet acted on the Company and OERI’s May 30, 2008 change of status filing. On October 27, 2008, the Company and OERI submitted to the FERC another change of status filing notifying FERC that the Company had acquired a 51 percent interest in the Redbud Facility in Oklahoma, which increases the size of its generation resources by 610 MW. This filing indicated that: (i) the Company’s acquisition of the Redbud Facility does not reflect a material departure from the characteristics relied upon in granting the Company/OERI market-based rate authority; (ii) the Company/OERI continue to lack generation market power in first-tier markets; and (iii) the Company’s acquisition of the Redbud Facility does not effect the Company’s or OERI’s previous analysis on transmission market power, affiliate abuse or barriers to entry. The FERC has not yet acted on the Company’s and OERI’s October 27, 2008 change of status filing.

North American Electric Reliability Council

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC approved the North American Electric Reliability Council (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. On April 19, 2007, the FERC approved the SPP as a Regional Entity whose primary function is to review and enforce compliance of reliability standards with all registered entities in the region. In March 2007, the FERC approved mandatory NERC reliability standards which became effective June 18, 2007. In November 2008, the Company completed its periodic NERC compliance audit. Resolution of any audit findings is expected in 2009; however, the Company does not expect the resolution of any audit findings to have a material impact on its operations. The Company is subject to a NERC readiness

evaluation and compliance audit every three years. The next readiness evaluation is scheduled for 2010 and the next compliance audit is scheduled for 2011.

National Legislative Initiatives

In October 2008, Congress enacted and the President signed into law the Emergency Economic Stabilization Act of 2008 which contains, among other things, provisions designed to provide programs to: (i) address the nation’s credit liquidity problems; (ii) provide disaster relief for adversely affected communities; (iii) preserve the value of homes, retirement accounts and promote job creation; and (iv) implement a wide range of tax provisions, including several of particular interest to the investor-owned utility sector. Among the tax provisions benefiting the utility sector are the extension of tax credits for renewable energy production, carbon mitigation and clean coal technology, plug-in hybrid vehicles, increasing residential and commercial building energy efficiency, energy efficient appliances and accelerated depreciation for smart meters and smart grid systems. Of particular interest to the Company is the extension through 2009 of the renewable energy production tax credit that was scheduled to expire at the end of 2008, which plays a prominent role regarding the financing and economics of wind energy projects.

In December 2008, Congress enacted and the President signed into law legislation providing some relief for companies regarding mandatory pension payment obligations that had become complicated by the economic downturn. This legislation allowed companies greater latitude in meeting their pension obligations through temporary adjustments regarding mandatory minimum distributions and plan funding targets. The utility industry supported this legislation and is seeking broader temporary adjustments for pension plan funding in 2009.

State Legislative Initiatives

House Bill 2813 (“HB 2813”) was signed into law in May 2008, at which time it became effective. HB 2813 was created in order to advance the development of Oklahoma’s vast wind power potential. This law provides for additional financial certainty for transmission line projects deemed necessary for the development of wind energy. The costs associated with such transmission lines are to be presumed to be recoverable if the lines are in service within five years of the passage of the law and meet the necessary criteria. The Company has announced its intentions to build transmission lines and substantially increase the amount of generation it produces by wind, and management believes that this legislation increases the likelihood of recovering the costs associated with the construction of transmission lines.

House Bill 1739 (“HB 1739”) was signed into law in May 2008, with an effective date of January 1, 2009. HB 1739 creates a system whereby utilities can divide their territories with the proper government oversight. The bill only relates to new customers in the territory and does not allow switching of existing customers. The law also codifies the right of investor-owned utilities to be able to continue serving in annexed territories of cities with municipal electric systems, where they can demonstrate a prior right to be in the annexed territory. The law is retroactive to include previous annexations as well as those that may occur in the future. This law also clarifies which utilities can serve in a territory annexed by a city because duplication of infrastructure has caused problems over the years since it possesses a potential safety hazard to line workers. The benefits of this law to the Company include being able to reduce future duplication of power lines and other infrastructure as well as clearly establishing the right to serve in areas previously considered legally questionable by certain parties.

Legislation was enacted in Oklahoma in the 1990’s that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation was delayed and seems unlikely to proceed anytime in the near future. Yet, if ultimately enacted, this legislation could deregulate the Company’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect the Company’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

Summary

The Energy Policy Act of 2005, the actions of the FERC, the restructuring legislation in Oklahoma and other factors are intended to increase competition in the electric industry. The Company has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While the Company is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and the Company is advocating this position vigorously.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder

Oklahoma Gas and Electric Company

We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2008 and 2007, and the related statements of income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oklahoma Gas and Electric Company at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oklahoma Gas and Electric Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 11, 2009 expressed an unqualified opinion thereon.

As discussed in Note 8 to the financial statements, in 2007 the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”

/s/ Ernst & Young LLP

Ernst & Young LLP

Oklahoma City, Oklahoma

February 11, 2009

Supplementary Data

Interim Financial Information (Unaudited)

In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present the Company’s results of operations for such periods:

Quarter ended (In millions)			March 31		June 30		September 30		December 31		Total

Operating revenues	2008	$	386.4	$	520.7	$	682.5	$	369.9	$	1,959.5
	2007		340.7		429.9		633.2		431.3		1,835.1

Operating income (loss)	2008	$	(0.7)	$	70.7	$	169.6	$	38.7	$	278.3
	2007		16.0		66.6		178.7		30.7		292.0

Net income (loss)	2008	$	(11.3)	$	30.9	$	107.1	$	16.3	$	143.0
	2007		1.9		35.1		109.0		15.7		161.7

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

None.

Item 9A. Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (“CEO”) and chief financial officer (“CFO”), allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company’s management, including the CEO and CFO, of the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

Management’s Report on Internal Control Over Financial Reporting

The management of Oklahoma Gas and Electric Company (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent auditors have issued an attestation report on the Company’s internal control over financial reporting. This report appears on the following page.

/s/ Peter B. Delaney		/s/ Danny P. Harris
Peter B. Delaney, Chairman of the Board, President		Danny P. Harris, Senior Vice President
and Chief Executive Officer		and Chief Operating Officer

/s/ Scott Forbes
Scott Forbes, Controller, Chief Accounting Officer
and Interim Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder

Oklahoma Gas and Electric Company

We have audited Oklahoma Gas and Electric Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oklahoma Gas and Electric Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Oklahoma Gas and Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2008 and 2007, and the related statements of income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008 of Oklahoma Gas and Electric Company and our report dated February 11, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Ernst & Young LLP

Oklahoma City, Oklahoma

February 11, 2009

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

CODE OF ETHICS POLICY

The Company maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on OGE Energy’s web site address www.oge.com under the heading “Investors”, “Corporate Governance.” The code of ethics will be provided, free of charge, upon request. The Company intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its web site at the location specified above. OGE Energy will also include in its proxy statement the Audit Committee financial expert.

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 has been omitted.

Item 11. Executive Compensation.

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 11 has been omitted.

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

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 12 has been omitted.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 has been omitted.

Item 14. Principal Accounting Fees and Services.

The following discussion relates to the audit fees paid by OGE Energy to its independent auditors for the services provided to OGE Energy and its subsidiaries, including the Company.

Fees for Independent Auditors

Audit Fees

Total audit fees for 2008 were $2,474,100 for OGE Energy’s 2008 financial statement audit. These fees include $1,560,000 for the integrated audit of OGE Energy’s annual financial statements and its internal control over financial reporting and $471,500 for services in support of debt and stock offerings. Total audit fees for 2007 were $2,302,000 for OGE Energy’s 2007 financial statement audit. These fees include $1,570,000 for the integrated audit of OGE Energy’s annual financial statements and its internal control over financial reporting and $332,000 for services in support of debt and stock offerings.

The aggregate audit fees include fees billed for the audit of OGE Energy’s annual financial statements and for the reviews of the financial statements included in OGE Energy’s Quarterly Reports on Form 10-Q. For 2008, this amount includes estimated billings for the completion of the 2008 audit, which were rendered after year-end.

Audit-Related Fees

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2008 were $117,400, of which $99,000 was for employee benefit plan audits and $18,400 for other audit-related services.

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2007 were $112,000, of which $94,500 was for employee benefit plan audits and $17,500 for other audit-related services.

Tax Fees

The aggregate fees billed for tax services for the fiscal year ended December 31, 2008 were $374,100. These fees include $143,330 for tax preparation and compliance ($70,500 for the review of Federal and state tax returns and $72,830 for assistance with examinations and other return issues) and $230,770 for other tax services.

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

All Other Fees

These were no other fees billed to OGE Energy in 2008 and 2007 for other services.

Audit Committee Pre-Approval Procedures

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

For 2008, 100% of the audit-related fees, tax fees and all other fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) 1. Financial Statements

The following financial statements and supplementary data are included in Part II, Item 8 of this Annual Report:

•	Balance Sheets at December 31, 2008 and 2007

•	Statements of Capitalization at December 31, 2008 and 2007

•	Statements of Income for the years ended December 31, 2008, 2007 and 2006

•	Statements of Changes in Stockholder’s Equity for the years ended December 31, 2008, 2007 and 2006

•	Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006

•	Notes to Financial Statements

•	Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)

•	Management’s Report on Internal Control Over Financial Reporting

•	Report of Independent Registered Public Accounting Firm (Audit of Internal Control)

Supplementary Data

•	Interim Financial Information

2. Financial Statement Schedule (included in Part IV)

Page

Schedule II - Valuation and Qualifying Accounts

106

All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.

3. Exhibits

Exhibit No.

Description

2.01

Asset Purchase Agreement, dated as of August 18, 2003 by and between the Company and NRG McClain LLC. (Certain exhibits and schedules were omitted and registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy’s Form 8-K filed August 20, 2003 (File No. 1-12579) and incorporated by reference herein)

2.02	Amendment No. 1 to Asset Purchase Agreement, dated as of October 22, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein)

2.03	Amendment No. 2 to Asset Purchase Agreement, dated as of October 27, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.04 to OGE Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein)

2.04	Amendment No. 3 to Asset Purchase Agreement, dated as of November 25, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.05 to OGE Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein)

2.05	Amendment No. 4 to Asset Purchase Agreement, dated as of January 28, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.06 to OGE Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein)

2.06	Amendment No. 5 to Asset Purchase Agreement, dated as of February 13, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.07 to OGE Energy’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein)

100

2.07	Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein)

2.08	Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein)

2.09	Amendment No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

2.10	Amendment No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

2.11	Amendment No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

2.12

Purchase and Sale Agreement, dated as of January 21, 2008, entered into by and among Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC and the Company (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein)

2.13

Asset Purchase Agreement, dated as of January 21, 2008, entered into by and among the Company, the Oklahoma Municipal Power Authority and the Grand River Dam Authority (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein)

3.01	Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01 to the Company’s Registration Statement No. 33-59805, and incorporated by reference herein)

3.02	Copy of Amended By-laws. (Filed as Exhibit 3.02 to OGE Energy’s Form 8-K filed January 23, 2007 (File No. 1-12579) and incorporated by reference herein)

4.01	Trust Indenture dated October 1, 1995, from the Company to Boatmen’s First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to Registration Statement No. 33-61821 and incorporated by reference herein)

4.02	Supplemental Trust Indenture No. 1 dated October 16, 1995, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed October 24, 1995 (File No. 1-1097) and incorporated by reference herein)

4.03	Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed July 17, 1997 (File No. 1-1097) and incorporated by reference herein)

4.04	Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed April 16, 1998 (File No. 1-1097) and incorporated by reference herein)

101

4.05	Supplemental Indenture No. 4, dated as of October 15, 2000, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to the Company’s Form 8-K filed October 20, 2000 (File No. 1-1097) and incorporated by reference herein)

4.06	Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to Registration Statement No. 333-104615 and incorporated by reference herein)

4.07	Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to the Company’s Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein)

4.08	Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to the Company’s Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein)

4.09	Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein)

4.09	Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein)

4.10	Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein)

10.01*

OGE Energy’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy’s Form 10-K for the year ended December 31, 1998 (File No. 1-12579) and incorporated by reference herein)

10.02*

OGE Energy’s 2003 Stock Incentive Plan. (Filed as Annex A to OGE Energy’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)

10.03*

OGE Energy’s 2003 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)

10.04

Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.02 to OGE Energy’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12579) and incorporated by reference herein)

10.05

Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between the Company and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

10.06

Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between the Company and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

10.07

Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between the Company and the Oklahoma Municipal Power Authority.

102

(Filed as Exhibit 10.05 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein)

10.08*

Amendment No. 1 to OGE Energy’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to OGE Energy’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)

10.09

Intrastate Firm No-Notice, Load Following Transportation and Storage Services Agreement dated as of May 1, 2003 between the Company and Enogex. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.24 to OGE Energy’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)

10.10*

Form of Performance Unit Agreement under OGE Energy’s 2008 Stock Incentive Plan. (Filed as Exhibit 10.12 to OGE Energy’s Form 10-K for the year ended December 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.11*

Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein)

10.12

Credit agreement dated December 6, 2006, by and between the Company, the Lenders thereto, Wachovia Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, and The Royal Bank of Scotland plc, Mizuho Corporate Bank and Union Bank of California, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed December 12, 2006 (File No. 1-12579) and incorporated by reference herein)

10.13*

Amendment No. 1 to OGE Energy’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to OGE Energy’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)

10.14*

Amendment No. 2 to OGE Energy’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to OGE Energy’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)

10.15*

OGE Energy’s Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.31 to OGE Energy’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein)

10.16

Ownership and Operating Agreement, dated as of January 21, 2008, entered into by and among the Company, the Oklahoma Municipal Power Authority and the Grand River Dam Authority (Filed as Exhibit 10.01 to OGE Energy’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein)

10.17*

Amendment No. 1 to OGE Energy Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.33 to OGE Energy’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein)

10.18*

Amendment No. 2 to OGE Energy Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.34 to OGE Energy’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein)

10.19

Letter of extension for the Company’s credit agreement dated November 11, 2007, by and between the Company and the Lenders thereto, related to the Company’s credit agreement dated December 6, 2006. (Filed as Exhibit 10.36 to OGE Energy’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein)

103

10.20*

Amendment No. 1 to OGE Energy’s 2003 Annual Incentive Compensation Plan. (Filed as Exhibit 10.02 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.21*

OGE Energy Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.03 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.22*

OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.23*

OGE Energy Deferred Compensation Plan, as amended and restated. (Filed as Exhibit 10.05 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.24*

Amendment No. 3 to OGE Energy’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.06 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.25*

Amendment No. 2 to OGE Energy’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.26*

OGE Energy’s 2008 Stock Incentive Plan. (Filed as Annex A to OGE Energy’s Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)

10.27*

OGE Energy’s 2008 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy’s Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)

10.28*

Amendment No. 3 to OGE Energy Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2008 (File No. 1-12579) and incorporated by reference herein)

10.29*

Form of Amended and Restated Change of Control Agreement with current officers of the Company. (Filed as Exhibit 10.01 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2008 (File No. 1-12579) and incorporated by reference herein)

10.30*

Amended and Restated Change of Control Agreement with Peter B. Delaney. (Filed as Exhibit 10.02 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2008 (File No. 1-12579) and incorporated by reference herein)

10.31*

Form of Change of Control Agreement with future officers of the Company. (Filed as Exhibit 10.03 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2008 (File No. 1-12579) and incorporated by reference herein)

10.32*

Form of Restricted Stock Agreement under 2008 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy’s Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12579) and incorporated by reference herein)

10.33*

Directors’ Compensation. (Filed as Exhibit 10.39 to OGE Energy’s Form 10-K for the year ended December 31, 2008 (File No. 1-12579) and incorporated by reference herein)

104

10.34*

Executive Officer Compensation. (Filed as Exhibit 10.40 to OGE Energy’s Form 10-K for the year ended December 31, 2008 (File No. 1-12579) and incorporated by reference herein)

10.35

Term Loan Agreement dated as of September 26, 2008 by and between the Company, UBS AG, as Administrative Agent, and UBS Securities LLC, as Sole Arranger and as Syndication Agent. (Filed as Exhibit 10.01 to OGE Energy’s Form 8-K filed October 2, 2008 (File No. 1-12579) and incorporated by reference herein)

10.36

Term Loan Agreement dated as of September 26, 2008 by and between the Company and Royal Bank of Scotland PLC, as Administrative Agent and as Syndication Agent. (Filed as Exhibit 10.02 to OGE Energy’s Form 8-K filed October 2, 2008 (File No. 1-12579) and incorporated by reference herein)

12.01

Calculation of Ratio of Earnings to Fixed Charges.

18.01

Letter from Ernst & Young LLP related to a change in accounting principle. (Filed as Exhibit 18.01 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein)

23.01

Consent of Ernst & Young LLP.

24.01

Power of Attorney.

31.01

Certifications Pursuant to Rule 13a-15(e)/15d-15(e) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01

Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01

Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995.

99.02

Copy of OCC order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed December 16, 2005 (File No. 1-12579) and incorporated by reference herein)

99.03

Copy of APSC order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.03 to OGE Energy’s Form 8-K filed January 11, 2007 (File No. 1-12579) and incorporated by reference herein)

* Represents executive compensation plans and arrangements,

105

OKLAHOMA GAS AND ELECTRIC COMPANY

SCHEDULE II - Valuation and Qualifying Accounts


			Additions
		Balance at	Charged to	Charged to		Balance at
		Beginning	Costs and	Other		End of
	Description	of Period	Expenses	Accounts	Deductions	Period

(In millions)

Year Ended December 31, 2006


Reserve for Uncollectible Accounts		$ 2.5	$ 6.8	$ ---	$ 6.0 (A)	$ 3.3


Year Ended December 31, 2007


Reserve for Uncollectible Accounts		$ 3.3	$ 6.0	$ ---	$ 5.9 (A)	$ 3.4


Year Ended December 31, 2008


Reserve for Uncollectible Accounts		$ 3.4	$ 2.9	$ ---	$ 4.0 (A)	$ 2.3

(A) Uncollectible accounts receivable written off, net of recoveries.

106

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 13^th day of February, 2009.

OKLAHOMA GAS AND ELECTRIC COMPANY

(Registrant)

By /s/ Peter B. Delaney

Peter B. Delaney

Chairman of the Board, President

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

Signature	Title	Date

/ s / Peter B. Delaney
Peter B. Delaney	Principal Executive
	Officer and Director;	February 13, 2009
/ s / Scott Forbes
Scott Forbes	Principal Financial Officer and
	Principal Accounting Officer.	February 13, 2009

Wayne H. Brunetti	Director;

Luke R. Corbett	Director;

John D. Groendyke	Director;

Kirk Humphreys	Director;

Robert Kelley	Director;

Linda P. Lambert	Director;

Robert O. Lorenz	Director;

Leroy C. Richie	Director; and

J. D. Williams	Director.

/ s / Peter B. Delaney
By Peter B. Delaney (attorney-in-fact)		February 13, 2009

107

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.

The Registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.

108


	Year Ended	Year Ended	Year Ended	Year Ended	Year Ended
(in thousands)	Dec 31, 2004	Dec 31, 2005	Dec 31, 2006	Dec 31, 2007	Dec 31, 2008

Earnings:
Pre-tax income	$160,635	$182,280	$234,093	$234,862	$195,410

Add Fixed Charges	42,235	52,380	66,974	61,064	85,151

Subtotal	202,870	234,660	301,067	295,926	280,561


Subtract:
Allowance for borrowed funds used during construction	1,662	2,233	4,487	3,989	3,950

Total Earnings	201,208	232,427	296,580	291,937	276,611

Fixed Charges:
Interest on long-term debt	36,890	42,118	50,301	50,860	67,274
Interest on short-term debt and other interest charges	2,247	7,314	14,300	8,047	15,774
Calculated interest on leased property	3,098	2,948	2,373	2,157	2,103

Total Fixed Charges	$42,235	$52,380	$66,974	$61,064	$85,151


Ratio of Earnings to Fixed Charges	4.76	4.44	4.43	4.78	3.25