OKLAHOMA GAS & ELECTRIC CO - FORM 10-K

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EX-23.01 - OG&AMP;E 2009 10-K EX 23.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex2301.htm
EX-99.01 - OG&AMP;E 2009 10-K EX 99.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex9901.htm
EX-31.01 - OG&AMP;E 2009 10-K EX 31.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex3101.htm
EX-32.01 - OG&AMP;E 2009 10-K EX 32.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex3201.htm
EX-24.01 - OG&AMP;E 2009 10-K EX 24.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex2401.htm
EX-12.01 - OG&AMP;E 2009 10-K EX 12.01 - OKLAHOMA GAS & ELECTRIC CO	ogande10kex1201.htm

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, 2009
	OR

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No 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, 2009, 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, 2010, 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, 2009

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	9
Fuel Supply and Generation	9
Environmental Matters	11
Finance and Construction	14
Employees	16
Access to Securities and Exchange Commission Filings	16

Item 1A. Risk Factors	16

Item 1B. Unresolved Staff Comments	22

Item 2. Properties	23

Item 3. Legal Proceedings	24

Item 4. Submission of Matters to a Vote of Security Holders	25
Executive Officers of the Registrant	26

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

Item 6. Selected Financial Data	29

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	53

Item 8. Financial Statements and Supplementary Data	55

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	102

Item 9A. Controls and Procedures	102

Item 9B. Other Information	105

Part III

Item 10. Directors, Executive Officers and Corporate Governance	105

Item 11. Executive Compensation	105

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters	105

Item 13. Certain Relationships and Related Transactions, and Director Independence	105

Item 14. Principal Accounting Fees and Services	105

Part IV

Item 15. Exhibits, Financial Statement Schedules	106

Signatures	114

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:

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

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

Ÿ	prices and availability of electricity, coal and natural gas;

Ÿ	business conditions in the energy industry;

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

Ÿ	unusual weather;

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

Ÿ	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;

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

Ÿ	changes in accounting standards, rules or guidelines;

Ÿ	the discontinuance of accounting principles for certain types of rate-regulated activities;

Ÿ	creditworthiness of suppliers, customers and other contractual parties; and

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

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I

Item 1. Business.

THE COMPANY

Introduction

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is subject to rate 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. 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.

The Company has been focused on increased investment to preserve system 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, provide energy management solutions to the Company’s customers through the Smart Grid program (discussed below) 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:

Ÿ	in January 2007, a 120 megawatt (“MW”) wind farm in northwestern Oklahoma (“Centennial”) was placed in service;

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

in 2008, the Company announced a “Positive Energy Smart Grid” initiative that will empower customers to proactively manage their energy consumption during periods of peak demand. As a result of the American Recovery and Reinvestment Act of 2009 (“ARRA”) signed by the President into law in February 2009, the Company requested a $130 million grant from the U.S. Department of Energy (“DOE”) in August 2009 to develop its Smart Grid technology. In late October 2009, the Company received notification from the DOE that its grant had been accepted by the DOE;

Ÿ	in 2008, the Company began construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”), which is a critical first step to increased wind development in western Oklahoma. This transmission line is expected to be in service by April 2010;

Ÿ	in June 2009, the Company received SPP approval to build four 345 kilovolt (“kV”) transmission lines referred to as “Balanced Portfolio 3E”, which the Company expects to begin constructing in early 2010. These transmission lines are expected to be in service between December 2012 and December 2014;

in September 2009, the Company signed power purchase agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma which the Company intends to add to its power-generation portfolio by the end of 2010. The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future;

Ÿ	in November and December 2009, the individual turbines were placed in service related to the OU Spirit wind project in western Oklahoma (“OU Spirit”), which added 101 MWs of wind capacity to the Company’s wind portfolio; and

the Company’s construction initiative from 2010 to 2015 includes approximately $2.6 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. The Company also is promoting Demand Side Management programs to encourage more efficient use of electricity. See “Recent Regulatory Matters – Conservation and Energy Efficiency Programs” for a further discussion. 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.

Increases in generation and the building of transmission lines are subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” and Note 13 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, 2009, 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 90 percent of its total electric operating revenues for the year ended December 31, 2009 from sales in Oklahoma and the remainder from sales in Arkansas.

The Company’s system control area peak demand during 2009 was approximately 6,418 MWs on July 13, 2009. The Company’s load responsibility peak demand was approximately 5,969 MWs on July 13, 2009. As reflected in the table below and in the operating statistics that follow, there were approximately 25.9 million megawatt-hour (“MWH”) sales to the Company’s customers (“system sales”) in 2009, 26.8 million MWH system sales in 2008 and 26.4 million MWH system sales in 2007. Variations in system sales for the three years are reflected in the following table:

		2009 vs. 2008		2008 vs. 2007
Year ended December 31 (In millions)	2009	Decrease	2008	Increase	2007
System Sales (A)	25.9	(3.4)%	26.8	1.5%	26.4

(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.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS

Year ended December 31 (In millions)	2009		2008		2007

ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)		25.0		25.7		23.8
Purchased		3.9		4.3		5.2
Total generated and purchased		28.9		30.0		29.0
Company use, free service and losses		(2.0)		(1.8)		(1.9)
Electric energy sold		26.9		28.2		27.1

ELECTRIC ENERGY SOLD (Millions of MWH)
Residential		8.7		9.0		8.7
Commercial		6.4		6.5		6.3
Industrial		3.6		4.0		4.2
Oilfield		2.9		2.9		2.8
Public authorities and street light		3.0		3.0		3.0
Sales for resale		1.3		1.4		1.4
System sales		25.9		26.8		26.4
Off-system sales (A)		1.0		1.4		0.7
Total sales		26.9		28.2		27.1

ELECTRIC OPERATING REVENUES (In millions)
Residential	$	717.9	$	751.2	$	706.4
Commercial		439.8		479.0		450.1
Industrial		172.1		219.8		221.4
Oilfield		132.6		151.9		140.9
Public authorities and street light		167.7		190.3		181.4
Sales for resale		53.6		64.9		68.8
Provision for rate refund		(0.6)		(0.4)		0.1
System sales revenues		1,683.1		1,856.7		1,769.1
Off-system sales revenues		31.8		68.9		35.1
Other		36.3		33.9		30.9
Total operating revenues	$	1,751.2	$	1,959.5	$	1,835.1

ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential		665,344		659,829		653,369
Commercial		85,537		85,030		83,901
Industrial		3,056		3,086		3,142
Oilfield		6,437		6,424		6,324
Public authorities and street light		16,124		15,670		15,446
Sales for resale		52		49		52
Total		776,550		770,088		762,234

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,083.50	$	1,145.05	$	1,086.03
Average annual use (kilowatt-hour (“KWH”))		13,197		13,659		13,325
Average price per KWH (cents)	$	8.21	$	8.38	$	8.15

(A) Sales to other utilities and power marketers.

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, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the DOE has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2009, approximately 89 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, eight 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.

Recent Regulatory Matters

2009 Oklahoma Rate Case Filing. On February 27, 2009, the Company filed its rate case with the OCC requesting a rate increase of approximately $110 million. On July 24, 2009, the OCC issued an order authorizing: (i) an annual net increase of approximately $48.3 million in the Company’s rates to its Oklahoma retail customers, which includes an increase in the residential customer charge from $6.50/month to $13.00/month, (ii) creation of a new recovery rider to permit the recovery of up to $20 million of capital expenditures and operation and maintenance expenses associated with the Company’s smart grid project in Norman, Oklahoma, which was implemented in February 2010, (iii) continued utilization of a return on equity (“ROE”) of 10.75 percent under various recovery riders previously approved by the OCC and (iv) recovery through the Company’s fuel adjustment clause of approximately $4.8 million annually of certain expenses that historically had been recovered through base rates. New electric rates were implemented August 3, 2009. The Company expects the impact of the rate increase on its customers and service territory to be minimal over the next 12 months as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries and from lower than forecasted fuel costs in 2010.

Arkansas Rate Case Filing. In August 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 in 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. On May 20, 2009, the APSC approved a general rate increase of approximately $13.3 million, which excludes approximately $0.3 million in storm costs. The APSC order also allows implementation of the Company’s “time-of-use” tariff which allows participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. The Company implemented the new electric rates effective June 1, 2009.

OU Spirit 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 OU Spirit. As discussed below, OU Spirit is part of the Company’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, the Company filed an application with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct OU Spirit at a cost of approximately $265.8 million. On October 15, 2009, all parties to this case signed a settlement agreement that would provide pre-approval of OU Spirit and authorize the Company to begin recovering the costs of OU Spirit through a rider mechanism as the 44 turbines were placed into service in November and December 2009 and began delivering electricity to the Company’s customers. The rider will be in effect until OU Spirit is added to the Company’s regulated rate base as part of the Company’s next general rate case, which is expected to be based on a 2010 test year and completed in 2011, at which time the rider will cease. The settlement agreement also assigns to the Company’s customers the proceeds from the sale of OU Spirit renewable energy credits to the University of Oklahoma. The settlement agreement permits the recovery of up to $270 million of eligible construction costs, including recovery of the costs of the conservation project for the lesser prairie chicken as discussed below. The net impact on the average residential customer’s 2010 electric bill is estimated to be approximately 90 cents per month, decreasing to 80 cents per month in 2011. On November 25, 2009, the Company received an order from the OCC

approving the settlement agreement in this case, with the rider being implemented on December 4, 2009. Capital expenditures associated with this project were approximately $270 million.

In connection with OU Spirit, in January 2008, the Company filed with the SPP for a Large Generator Interconnection Agreement (“LGIA”) for this project. Since January 2008, the SPP has been studying this requested interconnection to determine the feasibility of the request, the impact of the interconnection on the SPP transmission system and the facilities needed to accommodate the interconnection. Given the backlog of interconnection requests at the SPP, there has been significant delay in completing the study process and in the Company receiving a final LGIA. On May 29, 2009, the Company executed an interim LGIA, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. In connection with the interim LGIA, the Company posted a letter of credit with the SPP of approximately $10.9 million, which was later reduced to approximately $9.9 million in October 2009 and further reduced to approximately $9.2 million in February 2010, related to the costs of upgrades required for the Company to obtain transmission service from its new OU Spirit wind farm. The SPP filed the interim LGIA with the FERC on June 29, 2009. On August 27, 2009, the FERC issued an order accepting the interim LGIA, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid until the final LGIA can be put in place, which is expected by mid-2010.

In connection with OU Spirit and to support the continued development of Oklahoma’s wind resources, on April 1, 2009, the Company announced a $3.75 million project with the Oklahoma Department of Wildlife Conservation to help provide a habitat for the lesser prairie chicken, which ranks as one of Oklahoma’s more imperiled species. Through its efforts, the Company hopes to help offset the effect of wind farm development on the lesser prairie chicken and help ensure that the bird does not reach endangered status, which could significantly limit the ability to develop Oklahoma’s wind potential.

Renewable Energy Filing. The Company announced in October 2007 its goal to increase its wind power generation over the following four years from its then current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued a request for proposal (“RFP”) to wind developers for construction of up to 300 MWs of new capability, which the Company intends to add to its power-generation portfolio by the end of 2010. In June 2009, the Company announced that it had selected a short list of bidders for a total of 430 MWs and that it was considering acquiring more than the approximately 300 MWs of wind energy originally contemplated in the initial RFP. On September 29, 2009, the Company announced that, from its short list, it had reached agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under the terms of the agreements, CPV Keenan is to build a 150 MW wind farm in Woodward County and Edison Mission Energy is to build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output. On October 30, 2009, the Company filed separate applications with the OCC seeking pre-approval for the recovery of the costs associated with purchasing power from these projects. On December 9, 2009, all parties to these cases signed settlement agreements whereby the stipulating parties requested that the OCC issue orders: (i) finding that the execution of the power purchase agreements complied with the OCC competitive bidding rules, are prudent and are in the public’s interest, (ii) approving the power purchase agreements and (iii) authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. On January 5, 2010, the Company received an order from the OCC approving the power purchase agreements and authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. The two wind farms are expected to be in service by the end of 2010. Negotiations with the third bidder on the Company’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.

Windspeed Transmission Line Project. The Company filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct the Windspeed transmission line at a construction cost of approximately $211 million, plus approximately $7 million in allowance for funds used during construction (“AFUDC”), for a total of approximately $218 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 April 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to the Company’s Oklahoma customers. 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 the Windspeed transmission line 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 an expected 2011 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. At December 31, 2009, the construction costs and AFUDC incurred were approximately $184.9 million. 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 District EHV substation. In 2009, the Company received a favorable outcome in five local court cases challenging the Company’s use of eminent domain to obtain rights-of-way. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

SPP Transmission/Substation Projects. The SPP is a regional transmission organization (“RTO”) under the jurisdiction of the FERC, which was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP’s tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed has the first obligation to build.

There are several studies currently under review at the SPP including the Extra High Voltage (“EHV”) study that focuses on year 2026 and beyond to address issues of regional and interregional importance. The EHV study suggests overlaying the SPP footprint with a 345 kV, 500kV and 765kV transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP’s regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP’s future needs. The Company expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP’s plans.

In 2007, the SPP notified the Company to construct approximately 44 miles of new 345 kV transmission line which will originate at the existing Company Sooner 345 kV substation and proceed generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line will connect to the companion line being constructed in Kansas by Westar Energy. The line is estimated to be in service by June 2012. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

In January 2009, the Company received notification from the SPP to begin construction on approximately 50 miles of new 345 kV transmission line and substation upgrades at the Company’s Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative (“WFEC”) assigned to the Company the construction of 50 miles of line designated by the SPP to be built by the WFEC. The new line will extend from the Company’s Sunnyside substation near Ardmore, Oklahoma, approximately 100 miles to the Hugo substation owned by the WFEC near Hugo, Oklahoma. The Company began preliminary line routing and acquisition of rights-of-way in June 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. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

On April 28, 2009, the SPP approved the Balanced Portfolio 3E projects. Balanced Portfolio 3E includes four projects to be built by the Company and includes: (i) construction of approximately 120 miles of transmission line from the Company’s Seminole substation in a northeastern direction to the Company’s Muskogee substation at a cost of approximately $131 million for the Company, which is expected to be in service by December 2014, (ii) construction of approximately 72 miles of transmission line from the Company’s Woodward District EHV substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at a cost of approximately $120 million for the Company, which is expected to be in service by April 2014, (iii) construction of approximately 38 miles of transmission line from the Company’s Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of approximately $41 million for the Company, which is expected to be in service by December 2012 and (iv) construction of a new substation near Anadarko which is expected to consist of a 345/138 kV transformer and substation breakers and will be built in the Company’s portion

of the Cimarron-Lawton East Side 345 kV line at an estimated cost of approximately $8 million for the Company, which is expected to be in service by December 2012. On June 19, 2009, the Company received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, the Company responded to the SPP that the Company will construct the Balanced Portfolio 3E projects discussed above beginning in early 2010. The capital expenditures related to the Balanced Portfolio 3E projects are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

Conservation and Energy Efficiency Programs. In June and September 2009, the Company filed applications with the APSC and the OCC seeking approval of a comprehensive Demand Program portfolio designed to build on the success of its earlier programs and further promote energy efficiency and conservation for each class of Company customers. Several programs are proposed in these applications, ranging from residential weatherization to commercial lighting. In seeking approval of these new programs, the Company also seeks recovery of the program and related costs through a rider that would be added to customers’ electric bills. In Arkansas, the Company’s program is expected to cost approximately $2 million over an 18-month period and is expected to increase the average residential electric bill by less than $1.00 per month. In Oklahoma, the Company’s program is expected to cost approximately $45 million over three years and is expected to increase the average residential electric bill by less than $1.00 per month in 2010 and by approximately $1.40 per month in 2011 and 2012 depending on the success of the programs. In addition to program cost recovery, the OCC also granted the Company recovery of: (i) lost revenues resulting from the reduced KWH sales between rate cases and (ii) performance-based incentives of 15 percent of the net savings associated with the programs. A hearing in the APSC matter was held on October 29, 2009 and the Company received an order in this matter on February 3, 2010. A settlement agreement was signed in the OCC matter by several parties to this case on January 15, 2010 with a hearing being held on January 21, 2010, where the parties who had not previously signed the settlement agreement indicated that they did not oppose the settlement agreement. The Company received an order in the OCC matter on February 10, 2010.

Smart Grid Application. In February 2009, the President signed into law the ARRA. Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy. After review of the ARRA, the Company filed a grant request on August 4, 2009 for $130 million with the DOE to be used for the Smart Grid application in the Company’s service territory. On October 27, 2009, the Company received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million. Receipt of the grant monies is contingent upon successful negotiations with the DOE on final details of the award. The Company expects to file an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant during the first quarter of 2010. Separately, on November 30, 2009, the Company requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for the Company’s workforce. Recipients of the grant are expected to be announced in the first quarter of 2010.

See Note 13 of Notes to Financial Statements for further discussion of these matters, as well as a discussion of additional regulatory matters, including, among other things, system hardening filing, security enhancements filing, FERC formula rate filing and review of the Company’s fuel adjustment clause.

Regulatory Assets and Liabilities

The Company, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide 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, 2009 and 2008, the Company had regulatory assets of approximately $451.4 million and $464.3 million, respectively, and regulatory liabilities of approximately $363.0 million and $164.4 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.

Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If the Company were required to discontinue the application of accounting principles for certain types of rate-regulated activities 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.

Rate Structures

Oklahoma

The Company’s standard tariff rates include a cost-of-service component (including an authorized return on capital) plus a 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. 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. Another program being offered to the Company’s commercial and industrial customers is a voluntary load curtailment program called Load Reduction. 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 Company also has two rate classes, Public Schools-Demand and Public Schools Non-Demand, that will provide the Company with 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 implemented a military base rider that demonstrates Oklahoma’s continued commitment to our military partners.

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 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. Revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose alternative rate options. 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 the Company’s customers for many years to come.

Arkansas

The Company’s standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows the Company to pass through to customers (either positive or negative) the actual cost of fuel as compared to the fuel component in the Company’s most recently approved rate case. The Company’s Arkansas rate case order in May 2009 allows implementation of the Company’s “time-of-use” tariff which allows participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. The Company also offers certain qualifying customers a “day-ahead price” rate option which allows participating customers to adjust their electricity consumption based on a price signal received from the Company. The day-ahead price is based on the Company’s projected next day hourly operating costs.

Fuel Supply and Generation

During 2009, approximately 60 percent of the Company-generated energy was produced by coal-fired units, 38 percent by natural gas-fired units and two percent by wind-powered units. Of the Company’s 6,641 total MW capability

reflected in the table under Item 2. Properties, approximately 3,850 MWs, or 58.0 percent, are from natural gas generation, approximately 2,570 MWs, or 38.7 percent, are from coal generation and approximately 221 MWs, or 3.3 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	2009		2008		2007		2006		2005
Coal	$	1.65	$	1.11	$	1.10	$	1.10	$	0.98
Natural Gas	$	4.02	$	8.40	$	6.77	$	7.10	$	8.76
Weighted Average	$	2.50	$	3.30	$	3.13	$	2.98	$	3.21

The decrease in the weighted average cost of fuel in 2009 as compared to 2008 was primarily due to decreased natural gas prices partially offset by increased coal transportation rates in 2009 as discussed in Note 12 of Notes to Financial Statements. 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. 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, the APSC and the FERC.

Coal

All of the Company’s coal-fired units, with an aggregate capability of approximately 2,570 MWs, are designed to burn low sulfur western sub-bituminous coal. The Company purchases coal primarily under contracts expiring in years 2010, 2011 and 2015. In 2009, the Company purchased approximately 9.9 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.27 percent and can be burned in these units under existing Federal, state and local environmental standards (maximum of 1.2 lbs. of sulfur dioxide (“SO2”) per MMBtu) without the addition of SO2 removal systems. Based upon the average sulfur content and EPA certified emission data, the Company’s coal units have an approximate emission rate of 0.528 lbs. of SO2 per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 12 of Notes to Financial Statements.

In August 2009, the Company issued an RFP for coal supply purchases for periods from January 2011 through December 2015. The RFP process was completed during the fourth quarter of 2009 and resulted in two new coal contracts expiring in 2015. The coal supply purchases account for approximately 50 percent of the Company’s projected coal requirements during that timeframe. Additional coal supplies to fulfill the Company’s remaining 2011 through 2015 coal requirements will be acquired through additional RFPs.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” for a discussion of environmental matters which may affect the Company in the future, including its utilization of coal.

Natural Gas

In August 2009, the Company issued an RFP for gas supply purchases for periods from November 2009 through March 2010. The gas supply purchases from January through March 2010 account for approximately 18 percent of the Company’s projected 2010 natural gas requirements. The RFP process was completed on September 10, 2009. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2010. Additional gas supplies to fulfill the Company’s remaining 2010 natural gas requirements will be acquired through additional RFPs in early to mid-2010, along with monthly and daily purchases, all of which are expected to be made at market prices.

The Company utilizes a natural gas storage facility for storage services that allows the Company to maximize the value of its generation assets. Storage services are provided by Enogex as part of Enogex’s gas transportation and storage contract with the Company. At December 31, 2009, the Company had approximately 1.9 million MMBtu’s in natural gas storage valued at approximately $7.3 million.

Wind

The Company’s current wind power portfolio includes: (i) the 120 MW Centennial wind farm, (ii) the 101 MW OU Spirit wind farm placed in service in November and December 2009 and (iii) 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 that expires in 2018.

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 including 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 can impose burdensome 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 (“Federal Clean Water Act”) and comparable state statutes, prepare and file reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtain 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. The trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment. For example, as discussed below, in 2009, the EPA adopted a finding that greenhouse gases contribute to pollution and the EPA proposed rules related to the control of greenhouse gas emissions. 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 $1.9 million and $2.3 million, respectively, of the Company’s capital expenditures budgeted for 2010 and 2011 are to comply with environmental laws and regulations. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs associated with environmental quality will be approximately $20.9 million in 2010 as compared to approximately $19.9 million in 2009. 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” and Note 12 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.

In December 2008, an impoundment used for the disposal of coal ash by a coal-fired power plant in Kingston, Tennessee failed, releasing more than five million cubic yards of ash onto adjacent land and into a nearby river. Shortly thereafter, the EPA announced its intention to avert similar incidents by promulgating rules to regulate coal ash by the end of 2009 pursuant to its authority under the RCRA. However, in December 2009, the EPA announced that the deadline for promulgating those rules had been extended indefinitely due to the complexity of the technical analyses involved in the rulemaking process. Thus, the extent to which the EPA intends to regulate coal ash is uncertain at this time. At issue is whether the EPA intends to regulate coal ash as a hazardous waste pursuant to Subtitle C of the RCRA and the impact such regulation will have on its future disposal and beneficial use insofar as the Company is concerned. The Company’s coal-fired power plants do not dispose of coal ash on-site. Instead, the ash is commercially disposed off-site or is marketed for a variety of beneficial uses including those related to the cement/concrete manufacturing and road construction industries. Because of the uncertainty surrounding the EPA’s decision on how coal ash will be regulated, the financial impact on the Company is uncertain at this time.

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 generate wastes that either are or otherwise contain CERCLA hazardous substances, the Company could be subject to burdensome 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

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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” for a discussion of potentially significant environmental capital expenditures related to air emissions particularly as it relates to regional haze.

Water Discharges

The Company’s operations are subject to the Federal 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 Federal 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” for a discussion of water intake matters.

Climate Change

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. 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. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels. 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 is taking steps 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. 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 from generating units subject to the Federal Acid Rain Program and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. Sulfur hexafluoride and methane are also characterized by the EPA as greenhouse gases. The Company is a partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program, a voluntary program to reduce emissions of greenhouse gases.

In June 2009, the American Clean Energy and Security Act of 2009 (sometimes referred to as the Waxman-Markey global climate change bill) was passed in the U.S. House of Representatives. The bill includes many provisions that would potentially have a significant impact on the Company and its customers. The bill proposes a cap and trade regime, a renewable portfolio standard, electric efficiency standards, revised transmission policy and mandated investments in plug-in hybrid infrastructure and smart grid technology. Although proposals have been introduced in the U.S. Senate, including a proposal that would require greater reductions in greenhouse gas emissions than the American Clean Energy and Security Act of 2009, it is uncertain at this time whether, and in what form, legislation will be adopted by the U.S. Senate. Both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy. Compliance with any new laws or regulations

regarding the reduction of greenhouse gases could result in significant changes to the Company’s operations, significant capital expenditures by the Company and a significant increase in our cost of conducting business.

On September 22, 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The new reporting requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain Company facilities. The rule requires the collection of data beginning on January 1, 2010 with the first annual reports due to the EPA on March 31, 2011. Certain reporting requirements included in the initial proposed rules that may have significantly affected capital expenditures were not included in the final reporting rule. Additional requirements have been reserved for further review by the EPA with additional rulemaking possible. The outcome of such review and cost of compliance of any additional requirements is uncertain at this time.

On December 15, 2009, the EPA published their finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. Although the endangerment finding is being made in the context of greenhouse gas emissions from new motor vehicles, the finding is likely to result in other forms of regulation. Numerous petitions are pending at the EPA from various state and environmental groups seeking regulation of a variety of mobile sources (i.e., trucks, airplanes, ships, boats, equipment, etc.) and stationary sources. With the endangerment finding issued, the EPA is likely to begin acting on these petitions in 2010. Additionally, on December 2, 2009 the Center for Biological Diversity announced a petition with the EPA seeking promulgation of a greenhouse gas National Ambient Air Quality Standard (“NAAQS”).

On September 30, 2009, the EPA proposed two rules related to the control of greenhouse gas emissions. The first proposal, which is related to the prevention of significant deterioration and Title V tailoring, determines what sources would be affected by requirements under the Federal Clean Air Act programs for new and modified sources to control emissions of carbon dioxide and other greenhouse gas emissions. The second proposal addresses the December 2008 prevention of significant deterioration interpretive memo by the EPA, which declared that carbon dioxide is not covered by the prevention of significant deterioration provisions of the Federal Clean Air Act. The outcome of these proposals is uncertain at this time.

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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

Capital Expenditures

The Company’s estimates of capital expenditures are approximately: 2010 - $500 million, 2011 - $555 million, 2012 - $495 million, 2013 - $425 million, 2014 - $350 million and 2015 - $315 million. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s business) plus capital expenditures for known and committed projects (collectively referred to as the “Base Capital Expenditure Plan”). The table below summarizes the capital expenditures by category:

			Less than
			1 year		1-3 years		3-5 years		More than
(In millions)	Total		(2010)		(2011-2012)		(2013-2014)		5 years
Base Transmission	$	150	$	45	$	40	$	40	$	25
Base Distribution		1,320		235		430		435		220
Base Generation		205		30		70		70		35
Other		150		25		50		50		25
Total Base Transmission, Distribution,
Generation and Other		1,825		335		590		595		305
Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kV)		120		30		90		---		---
Sooner-Rose Hill (345 kV)		65		10		55		---		---
Windspeed (345 kV)		25		25		---		---		---
Balanced Portfolio 3E Projects		300		10		170		120		---
Total Transmission Projects		510		75		315		120		---
Other Projects:
Smart Grid Program (A)		230		40		120		60		10
System Hardening		35		20		15		---		---
OU Spirit		10		10		---		---		---
Other		30		20		10		---		---
Total Other Projects		305		90		145		60		10
Total Known and Committed Projects		815		165		460		180		10
Total (B)	$	2,640	$	500	$	1,050	$	775	$	315

(A) These capital expenditures are contingent upon OCC approval of the Company’s Positive Energy Smart Grid program and are net of the Smart Grid $130 million grant approved by the DOE.

(B) The Base Capital Expenditure Plan above excludes any environmental expenditures associated with Best Available Retrofit Technology (“BART”) requirements due to the uncertainty regarding BART costs. As discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations,” pursuant to a proposed regional haze agreement the Company has agreed to install low nitrogen oxide (“NOX”) burners and related equipment at the three affected generating stations. Preliminary estimates indicate the cost will be approximately $100 million (plus or minus 30 percent). For further information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations.”

Additional capital expenditures beyond those identified in the table above, including incremental growth opportunities in transmission assets and wind generation assets, will be evaluated based upon their impact upon achieving the Company’s financial objectives.

Pension and Postretirement Benefit Plans

During each of 2009 and 2008, 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 in each of 2009 and 2008 was the Company’s portion. During 2010, 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 Condition 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, 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 or advances from OGE Energy generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper, by borrowings under its revolving credit agreement or by advances from OGE Energy. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2009 or 2008. At December 31, 2009, the Company had no outstanding advances from OGE Energy. At December 31, 2008, the Company had approximately $17.6 million in outstanding advances from OGE Energy. 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 10 of Notes to Financial Statements for a discussion of OGE Energy’s and the Company’s short-term debt activity. The Company has less than $0.1 million and approximately $50.7 million of cash and cash equivalents at December 31, 2009 and 2008, respectively.

Registration Statement Filing

During the first half of 2010, the Company expects to file a Form S-3 Registration Statement to register debt securities for sale by the Company.

Expected Issuance of Long-Term Debt

The Company expects to issue approximately $250 million of long-term debt in mid-2010, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.

EMPLOYEES

The Company had 2,127 employees at December 31, 2009.

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 “Investor Relations”, “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. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.

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. 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 rate 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 rate 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. For example, the EPA has proposed lowering the ambient standards for ozone and SO2. If these standards are adopted, reductions in emissions from our electric generating facilities could be required, which may result in significant capital and operating expenditures.

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 unable 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, litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. Recently, two Federal courts of appeal have reinstated nuisance-type claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. Although the Company is not a defendant in either proceeding, additional litigation in Federal and state courts over these issues is expected.

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. Additional reporting is required by a rule issued by the EPA in 2009, and the EPA has proposed rules that could regulate carbon dioxide emissions under the Federal Clean Air Act. For a further discussion of environmental matters that may affect the Company, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” and “Environmental Laws and Regulations” in Note 12 of Notes to Financial Statements. 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.

We are subject to physical and financial risks associated with climate change.

There is a growing concern that emissions of greenhouse gases are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change could include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. The Company’s operations are not sensitive to potential future sea-level rise as it does not operate in coastal areas. However, the Company’s power delivery systems are vulnerable to damage from extreme weather events, such as ice storms, tornadoes and severe thunderstorms. These types of extreme weather events are common on the Company system, so the Company includes storm restoration in its budgeting process as a normal business expense. To the extent the frequency of extreme weather events increases, this could increase the Company’s cost of providing service. The Company’s electric generating facilities are designed to withstand the effects of extreme weather events, however, extreme weather conditions increase the stress placed on such systems. If climate change results in temperature increases in the Company’s service territory, the Company could expect increased electricity demand due to the increase in temperature and longer warm seasons. While this increase in demand could lead to increased energy consumption, it could also create a physical strain on the Company’s generating resources. At the same time, the Company could face restrictions on the ability to meet that demand if, due to drought severity, there is a lack of sufficient water for use in cooling during the electricity generating process.

In addition to the above cited risks, to the extent that any climate change adversely affects the national or regional economic health through increased rates caused by the inclusion of additional regulatory imposed costs (carbon dioxide taxes or costs associated with additional regulatory requirements), OGE Energy may be adversely impacted. A declining economy could adversely impact the overall financial health of OGE Energy because of lack of load growth and decreased sales opportunities.

To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

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 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 compliance audit every three years as well as periodic spot check audits 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. 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.

We are subject to information security risks.

A security breach of our information systems could impact the reliability of the generation fleet and/or reliability of the transmission and distribution system or subject us to financial harm associated with theft or inappropriate release of certain types of operating or customer information. We cannot accurately assess the probability that a security breach may occur, despite the measures we have taken to prevent such a breach, and we are unable to quantify the potential impact of such an event.

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.

We engage in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on our earnings and cash flows.

We are exposed to changes in commodity prices in our operations. To minimize the risk of commodity prices, we may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas.

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.

OGE Energy has a qualified defined benefit retirement plan (“Pension Plan”) that covers substantially all of our employees hired before December 1, 2009. In October 2009, OGE Energy’s Pension Plan and OGE Energy’s qualified defined contribution retirement plan (“401(k) Plan”) were amended, effective December 31, 2009, to offer a one-time irrevocable election for eligible employees, depending on their hire date, to select a future retirement benefit combination from OGE Energy’s Pension Plan and OGE Energy’s 401(k) Plan. Also, effective December 1, 2009, OGE Energy’s Pension Plan is no longer being offered to future employees of the Company. OGE Energy also has defined benefit 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 OGE Energy’s assumptions at December 31, 2009, OGE Energy expects to continue to make future contributions to maintain required funding levels. It is OGE Energy’s 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.

All employees hired prior to February 1, 2000 participate in defined benefit 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 factors 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 36 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 agreement 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 market turmoil in late 2008 and early 2009. Pricing grids associated with our credit facility 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.

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

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

Ÿ	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;

Ÿ	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

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

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.

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 11 generating stations with an aggregate capability of approximately 6,641 MWs at December 31, 2009. The following tables set forth information with respect to the Company’s electric generating facilities, all of which are located in Oklahoma.

						2009				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		---	%	(B)		---
	4	1977	Steam-Turbine	Coal	Base Load		51.3	%			505
	5	1978	Steam-Turbine	Coal	Base Load		69.4	%			517
	6	1984	Steam-Turbine	Coal	Base Load		63.8	%			502		1,524
Seminole	1	1971	Steam-Turbine	Gas	Base Load		23.1	%			491
	1GT	1971	Combustion-Turbine	Gas	Peaking		0.1	%	(C)		17
	2	1973	Steam-Turbine	Gas	Base Load		22.7	%			494
	3	1975	Steam-Turbine	Gas/Oil	Base Load		18.3	%			502		1,504
Sooner	1	1979	Steam-Turbine	Coal	Base Load		68.4	%			522
	2	1980	Steam-Turbine	Coal	Base Load		72.2	%			524		1,046
Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load		15.8	%			159
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load		19.2	%			227
	8	1969	Steam-Turbine	Gas	Base Load		4.6	%			380
	9	2000	Combustion-Turbine	Gas	Peaking		4.7	%	(C)		46
	10	2000	Combustion-Turbine	Gas	Peaking		4.3	%	(C)		46		858
Mustang	1	1950	Steam-Turbine	Gas	Peaking		2.3	%	(C)		50
	2	1951	Steam-Turbine	Gas	Peaking		2.3	%	(C)		51
	3	1955	Steam-Turbine	Gas	Base Load		9.9	%			113
	4	1959	Steam-Turbine	Gas	Base Load		13.6	%			253
	5A	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking		0.6	%	(C)		32
	5B	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking		1.1	%	(C)		32		531
Redbud (D)	1	2003	Combined Cycle	Gas	Base Load		35.3	%			149
	2	2003	Combined Cycle	Gas	Base Load		45.4	%			147
	3	2003	Combined Cycle	Gas	Base Load		43.9	%			148
	4	2003	Combined Cycle	Gas	Base Load		46.6	%			145		589
McClain (E)	1	2001	Combined Cycle	Gas	Base Load		82.7	%			346		346
Woodward	1	1963	Combustion-Turbine	Gas	Peaking		---	%	(B)	(C)	---		---
Enid	1	1965	Combustion-Turbine	Gas	Peaking		---	%	(B)	(C)	---
	2	1965	Combustion-Turbine	Gas	Peaking		---	%	(B)	(C)	---
	3	1965	Combustion-Turbine	Gas	Peaking		0.2	%	(C)		11
	4	1965	Combustion-Turbine	Gas	Peaking		0.1	%	(C)		11		22
Total Generating Capability (all stations, excluding winds station)													6,420

						2009				Unit		Station
		Year		Number of	Fuel	Capacity				Capability		Capability
Station		Installed	Location	Units	Capability	Factor (A)				(MW)		(MW)
Centennial		2007	Woodward, OK	80	Wind		34.2	%			1.5		120
OU Spirit (F)		2009	Woodward, OK	44	Wind		---	%			2.3		101
Total Generating Capability (wind stations)													221
(A) 2009 Capacity Factor = 2009 Net Actual Generation / (2009 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
(B) This unit did not demonstrate summer capability in 2009 as prescribed by the SPP criteria.
(C) Peaking units are used when additional short-term capacity is required.
(D) 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.
(E) Represents the Company’s 77 percent ownership interest in the McClain Plant.
(F) OU Spirit’s 44 turbines were placed into service in November and December 2009.

At December 31, 2009, the Company’s transmission system included: (i) 48 substations with a total capacity of approximately 9.9 million kilo Volt-Amps (“kVA”) and approximately 4,064 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of approximately 2.5 million kVA and approximately 271 structure miles of lines in Arkansas. The Company’s distribution system included: (i) 348 substations with a total capacity of approximately 8.9 million kVA, 26,316 structure miles of overhead lines, 1,729 miles of underground conduit and 8,806 miles of underground conductors in Oklahoma and (ii) 38 substations with a total capacity of approximately 1.1 million kVA, 2,239 structure miles of overhead lines, 187 miles of underground conduit and 567 miles of underground conductors in Arkansas.

The Company owns 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, 2009, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $1.8 billion and gross retirements were approximately $132.8 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to approximately 28.0 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2009.

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 12 and 13 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 was a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleged: (a) each of the named defendants had improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts were improper; (c) transactions by affiliated companies were not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg sought the following damages: (a) additional royalties which he claimed 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. Various appeals and hearings were held in this matter from 2006 to late 2009. In October 2009, this matter concluded with the dismissal of all complaints against the Company. The Company now considers this case closed.

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 other 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.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007. On September 18, 2009, the court entered its order denying class certification. On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing. No ruling on this motion has been made.

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. On March 10, 2009, the Oklahoma Attorney General, the Company, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed. On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the OCC order which authorizes the Company to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether the Company’s collection and remittance of such sales tax should be discontinued prospectively. On December 21, 2009, the plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny the Company’s writ of prohibition and to remand the cause to the District Court. On December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to dismiss the cause and close the cause at the OCC. If the OCC Staff’s motion is granted, the plaintiffs would be required to file a new cause in order to ask for prospective relief. In its motion, the OCC Staff stated that the plaintiff’s counsel advised the OCC Staff counsel that the plaintiffs have no desire to seek a determination regarding prospective relief from the OCC. It is unknown whether the plaintiffs will attempt to continue the District Court action. The Company believes that the lawsuit 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 arbitration hearing was completed recently and the next step is briefing by the parties. 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 18, 2010:

Name	Age	Title

Peter B. Delaney	56	Chairman of the Board, President and Chief Executive Officer

Danny P. Harris	54	Senior Vice President and Chief Operating Officer

Sean Trauschke	42	Vice President and Chief Financial Officer

Patricia D. Horn	51	Vice President - Governance and Environmental, Health &
		Safety; Corporate Secretary

Gary D. Huneryager	59	Vice President - Internal Audits

S. Craig Johnston	49	Vice President - Strategic Planning and Marketing

Jesse B. Langston	47	Vice President - Utility Commercial Operations

Jean C. Leger, Jr.	51	Vice President - Utility Operations

Cristina F. McQuistion	45	Vice President - Process and Performance Improvement

Stephen E. Merrill	45	Vice President - Human Resources

Howard W. Motley	61	Vice President - Regulatory Affairs

Reid V. Nuttall	52	Vice President - Chief Information Officer

Melvin H. Perkins, Jr.	61	Vice President - Power Delivery

Paul L. Renfrow	53	Vice President - Public Affairs

John Wendling, Jr.	53	Vice President - Power Supply

Max J. Myers	35	Treasurer

Scott Forbes	52	Controller and Chief Accounting Officer

Jerry A. Peace	47	Chief Risk Officer

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Harris, Trauschke, Huneryager, Johnston, Merrill, Nuttall, Renfrow, Myers, Forbes and Peace and Ms. Horn 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 Shareowners of OGE Energy, currently scheduled for May 20, 2010.

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
	2005 – Present:	Chief Executive Officer of Enogex LLC
	2007:	President and Chief Operating Officer of OGE Energy and the
		Company
	2005 – 2007:	Executive Vice President and Chief Operating Officer of
		OGE Energy and the Company
	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.
	2005:	Vice President and Chief Operating Officer of Enogex Inc.

Sean Trauschke	2009 – Present:	Vice President and Chief Financial Officer of OGE Energy and the
		Company and Chief Financial Officer of Enogex LLC
	2007 – 2009:	Senior Vice President – Investor Relations and Financial Planning
		of Duke Energy
	2006 – 2007:	Vice President – Investor Relations of Duke Energy
	2005 – 2006:	Vice President and Chief Risk Officer of Duke Energy (electric
		utility)

Patricia D. Horn	2010 – Present:	Vice President – Governance and Environmental, Health & Safety;
		Corporate Secretary of OGE Energy and the Company
	2005 – 2010:	Vice President – Legal, Regulatory and Environmental Health &
		Safety, General Counsel and Secretary of Enogex LLC
	2005 – 2010:	Assistant General Counsel of OGE Energy

Gary D. Huneryager	2005 – Present:	Vice President – Internal Audits of OGE Energy and the
		Company
	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
	2005 – 2007:	Senior Vice President – Worldwide Oil & Gas Markets of Air
		Liquide (industrial gases company)

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

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

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
	2005 – 2007:	Executive Vice President – Member Services of Teleflora
		(floral industry and software services to floral industry company)

Name	Business Experience

Stephen E. Merrill	2009 – Present:	Vice President – Human Resources of OGE Energy and the
		Company
	2007 – 2009:	Vice President and Chief Financial Officer of Enogex LLC
	2006 – 2007:	Senior Vice President and Chief Financial Officer of Cayenne
		Drilling, LLC and Sunstone Energy Group LLC (oil and gas
		company)
	2005 – 2006:	Director of U.S. Operations at Plains All-American Pipeline L.P
		(natural gas pipeline company)

Howard W. Motley	2006 – Present:	Vice President – Regulatory Affairs of the Company
	2005 – 2006:	Director – Regulatory Affairs and Strategy of the Company

Reid V. Nuttall	2009 – Present:	Vice President – Chief Information Officer of OGE Energy and
		the Company
	2006 – 2009:	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)
	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
	2005 – 2007:	Vice President – Transmission of the Company

Paul L. Renfrow	2005 – Present:	Vice President – Public Affairs of OGE Energy and the Company
	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
	2005:	Plant Manager – Sooner Power Plant of the Company

Max J. Myers	2009 – Present:	Treasurer 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
	2005:	Director of Corporate Finance and Development of Westar Energy,
		Inc. (electric utility)

Scott Forbes	2005 – Present:	Controller and Chief Accounting Officer of OGE Energy and
		the Company
	2008 – 2009:	Interim Chief Financial Officer of OGE Energy and the Company
	2005:	Chief Financial Officer of First Choice Power (retail electric
		provider)
	2005:	Senior Vice President and Chief Financial Officer of Texas
		New Mexico Power Company (electric utility)

Jerry A. Peace	2008 – Present:	Chief Risk Officer of OGE Energy and the Company
	2005 – 2008:	Chief Risk Officer and Compliance Officer of OGE Energy
		and the Company

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 2009, the Company declared no dividends to OGE Energy. During 2008 and 2007, the Company declared dividends of approximately $35.0 million and $56.0 million, respectively, to OGE Energy.

Item 6. Selected Financial Data.

HISTORICAL DATA

Year ended December 31	2009		2008		2007		2006		2005
SELECTED FINANCIAL DATA

(In millions)

Results of Operations Data:
Operating revenues	$	1,751.2	$	1,959.5	$	1,835.1	$	1,745.7	$	1,720.7
Cost of goods sold		796.3		1,114.9		1,025.1		950.0		994.2
Gross margin on revenues		954.9		844.6		810.0		795.7		726.5
Other operating expenses		600.8		566.3		518.0		501.8		494.3
Operating income		354.1		278.3		292.0		293.9		232.2
Interest income		1.1		4.4		---		1.9		2.6
Allowance for equity funds used during construction		15.1		---		---		4.1		---
Other income (loss)		20.4		3.6		5.0		4.0		(2.8)
Other expense		6.7		11.8		7.2		9.7		2.5
Interest expense		93.6		79.1		54.9		60.1		47.2
Income tax expense		90.0		52.4		73.2		84.8		52.6
Net income	$	200.4	$	143.0	$	161.7	$	149.3	$	129.7

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	4,467.6	$	3,955.5	$	3,233.6	$	2,979.1	$	2,670.2
Total assets	$	5,478.1	$	4,851.2	$	3,874.9	$	3,589.7	$	3,255.0
Long-term debt	$	1,541.8	$	1,541.4	$	843.4	$	843.3	$	844.0
Total stockholder’s equity	$	2,024.3	$	1,824.3	$	1,423.3	$	1,322.0	$	1,116.0

CAPITALIZATION RATIOS (A)
Stockholder’s equity		56.8%		54.2%		62.8%		61.1%		56.9%
Long-term debt		43.2%		45.8%		37.2%		38.9%		43.1%

RATIO OF EARNINGS TO
FIXED CHARGES (B)
Ratio of earnings to fixed charges		3.71		3.25		4.78		4.43		4.44
(A) Capitalization ratios = [Total stockholder’s equity / (Total stockholder’s equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholder’s equity + Long-term debt + Long-term debt due within one year)]. (B) For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and (ii) 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

Executive Overview

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. OGE Energy intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business.

Ÿ	in January 2007, a 120 megawatt (“MW”) wind farm in northwestern Oklahoma was placed in service;

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

Ÿ	in 2008, the Company began construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”), which is a critical first step to increased wind development in western Oklahoma. This transmission line is expected to be in service by April 2010;

in June 2009, the Company received Southwest Power Pool (“SPP”) approval to build four 345 kilovolt (“kV”) transmission lines referred to as “Balanced Portfolio 3E”, which the Company expects to begin constructing in early 2010. These transmission lines are expected to be in service between December 2012 and December 2014;

Ÿ	in November and December 2009, the individual turbines were placed in service related to the OU Spirit wind project in western Oklahoma (“OU Spirit”), which added 101 MWs of wind capacity to the Company’s wind portfolio; and

The Company continues to pursue additional renewable energy and the construction of associated transmission facilities required to support this renewable expansion. The Company also is promoting Demand Side Management programs to encourage more efficient use of electricity. See Note 13 of Notes to Financial Statements (Conservation and Energy Efficiency Programs) for a further discussion. 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.

Increases in generation and the building of transmission lines are subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of transmission lines, the 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” and Note 13 of Notes to Financial Statements.

Summary of Operating Results

2009 compared to 2008. The Company reported net income of approximately $200.4 million and $143.0 million in 2009 and 2008, respectively, an increase of approximately $57.4 million, primarily due to a higher gross margin on revenues (“gross margin”), primarily due to rate increases and riders partially offset by milder weather and lower demand and related revenues by non-residential customers, and a higher allowance for equity funds used during construction (“AEFUDC”) partially offset by higher depreciation and amortization expense, higher interest expense and higher income tax expense.

2008 compared to 2007. The Company reported net income of approximately $143.0 million and $161.7 million in 2008 and 2007, respectively, a decrease of approximately $18.7 million, 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 due to increased rates from various regulatory riders implemented in 2008 and lower income tax expense.

Recent Developments and Regulatory Matters

Changes in Capital Markets

The volatility in global capital markets experienced in late 2008 and early 2009 led to a reduction in the value of long-term investments held in OGE Energy’s pension trust and postretirement benefit plan trusts. However, since the end of the first quarter of 2009, the market values have partially recovered from the decline in value experienced in late 2008 and early 2009.

Global Climate Change and Environmental Concerns

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. In June 2009, the U.S. House of Representatives passed legislation that would regulate greenhouse gas emissions by instituting a cap-and-trade-system, in which a cap on U.S. greenhouse gas emissions would be established starting in 2012 at a level three percent below the baseline 2005 level. The cap would decline over time until in 2050 it reaches 83 percent below the baseline level. Emission allowances, which are rights to emit greenhouse gases, would be both allocated for free and auctioned. In addition, the legislation contains a renewable energy standard of 25 percent by the year 2025 and an energy efficiency mandate for electric and natural gas utilities, as well as other requirements. Legislation pending in the U.S. Senate proposes to regulate greenhouse gas emissions by instituting a cap-and-trade-system, with primarily the same target levels proposed by the House bill; however, the proposed Senate bill is more aggressive in its 2020 target – a reduction to 20 percent below 2005 levels by 2020 (versus 17 percent in the House bill). It is uncertain at this time whether, and in what form, such legislation will ultimately be adopted. 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 capital expenditures and compliance costs.

Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region. Adoption of renewable portfolio

standards would be expected to increase the region’s reliance on wind generation. The Company believes it can leverage its unique geographic position to develop renewable energy resources for wind and transmission to deliver the renewable energy.

2009 Oklahoma Rate Case Filing

On February 27, 2009, the Company filed its rate case with the OCC requesting a rate increase of approximately $110 million. On July 24, 2009, the OCC issued an order authorizing: (i) an annual net increase of approximately $48.3 million in the Company’s rates to its Oklahoma retail customers, which includes an increase in the residential customer charge from $6.50/month to $13.00/month, (ii) creation of a new recovery rider to permit the recovery of up to $20 million of capital expenditures and operation and maintenance expenses associated with the Company’s smart grid project in Norman, Oklahoma, which was implemented in February 2010, (iii) continued utilization of a return on equity of 10.75 percent under various recovery riders previously approved by the OCC and (iv) recovery through the Company’s fuel adjustment clause of approximately $4.8 million annually of certain expenses that historically had been recovered through base rates. New electric rates were implemented August 3, 2009. The Company expects the impact of the rate increase on its customers and service territory to be minimal over the next 12 months as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries and from lower than forecasted fuel costs in 2010.

Arkansas Rate Case Filing

In August 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 in 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. On May 20, 2009, the APSC approved a general rate increase of approximately $13.3 million, which excludes approximately $0.3 million in storm costs discussed below. The APSC order also allows implementation of the Company’s “time-of-use” tariff which allows participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. The Company implemented the new electric rates effective June 1, 2009.

OU Spirit Wind Power Project

In July 2008, the Company signed contracts for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with OU Spirit. As discussed below, OU Spirit is part of the Company’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, the Company filed an application with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct OU Spirit at a cost of approximately $265.8 million. In November 2009, the Company received an order from the OCC authorizing the recovery of up to $270 million of eligible construction costs, including recovery of the costs of the conservation project for the lesser prairie chicken as discussed below, through a rider mechanism as the 44 turbines were placed into service in November and December 2009 and began delivering electricity to the Company’s customers. The rider will be in effect until OU Spirit is added to the Company’s regulated rate base as part of the Company’s next general rate case, which is expected to be based on a 2010 test year and completed in 2011, at which time the rider will cease. The order also assigns to the Company’s customers the proceeds from the sale of OU Spirit renewable energy credits to the University of Oklahoma. The rider was implemented on December 4, 2009 and the net impact of the rider on the average residential customer’s 2010 electric bill is estimated to be approximately 90 cents per month, decreasing to 80 cents per month in 2011. Capital expenditures associated with this project were approximately $270 million.

In connection with OU Spirit, in January 2008, the Company filed with the SPP for a Large Generator Interconnection Agreement (“LGIA”) for this project. Since January 2008, the SPP has been studying this requested interconnection to determine the feasibility of the request, the impact of the interconnection on the SPP transmission system and the facilities needed to accommodate the interconnection. Given the backlog of interconnection requests at the SPP, there has been significant delay in completing the study process and in the Company receiving a final LGIA. On May 29, 2009, the Company executed an interim LGIA, allowing OU Spirit to interconnect into the transmission grid, subject to certain conditions. In connection with the interim LGIA, the Company posted a letter of credit with the SPP of approximately $10.9 million, which was later reduced to approximately $9.9 million in October 2009 and further reduced to approximately $9.2 million in February 2010, related to the costs of upgrades required for the Company to obtain transmission service from its new OU Spirit wind farm. The SPP filed the interim LGIA with the FERC on June 29, 2009.

On August 27, 2009, the FERC issued an order accepting the interim LGIA, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid until the final LGIA can be put in place, which is expected by mid-2010.

Renewable Energy Filing

The Company announced in October 2007 its goal to increase its wind power generation over the following four years from its then current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued a request for proposal (“RFP”) to wind developers for construction of up to 300 MWs of new capability which the Company intends to add to its power-generation portfolio by the end of 2010. In June 2009, the Company announced that it had selected a short list of bidders for a total of 430 MWs and that it was considering acquiring more than the approximately 300 MWs of wind energy originally contemplated in the initial RFP. On September 29, 2009, the Company announced that, from its short list, it had reached agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under the terms of the agreements, CPV Keenan is to build a 150 MW wind farm in Woodward County and Edison Mission Energy is to build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output. On October 30, 2009, the Company filed separate applications with the OCC seeking pre-approval for the recovery of the costs associated with purchasing power from these projects. On December 9, 2009, all parties to these cases signed settlement agreements whereby the stipulating parties requested that the OCC issue orders: (i) finding that the execution of the power purchase agreements complied with the OCC competitive bidding rules, are prudent and are in the public’s interest, (ii) approving the power purchase agreements and (iii) authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. On January 5, 2010, the Company received an order from the OCC approving the power purchase agreements and authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. The two wind farms are expected to be in service by the end of 2010. Negotiations with the third bidder on the Company’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.

Smart Grid Application

In February 2009, the President signed into law the ARRA. Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy. After review of the ARRA, the Company filed a grant request on August 4, 2009 for $130 million with the DOE to be used for the Smart Grid application in the Company’s service territory. On October 27, 2009, the Company received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million. Receipt of the grant monies is contingent upon successful negotiations with the DOE on final details of the award. The Company expects to file an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant during the first quarter of 2010. Separately, on November 30, 2009, the Company requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for the Company’s workforce. Recipients of the grant are expected to be announced in the first quarter of 2010.

2010 Outlook

OGE Energy projects the Company to earn approximately $207 million to $217 million in 2010. The key factors and assumptions include:

Ÿ	Normal weather patterns are experienced for the year;

Ÿ	Gross margin on revenues of approximately $1.05 billion to $1.06 billion. The key assumptions for gross margin are listed below:

Ÿ	Sales growth of approximately 0.9 percent on a weather adjusted basis; and

Ÿ	The Windspeed transmission line is in service with the rider effective April 1, 2010;

Ÿ	Operating expenses of approximately $655 million to $665 million, with operation and maintenance expenses comprising approximately 60 percent of total;

Ÿ	Interest expense of approximately $105 million to $115 million, which assumes approximately $250 million of additional long-term debt issued by the Company in mid-2010;

Ÿ	AEFUDC income of approximately $5 million; and

Ÿ	An effective tax rate of approximately 27 percent.

The Company has significant seasonality in its earnings. The Company typically shows minimal earnings 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, 2009, 2008 and 2007 and the Company’s financial position at December 31, 2009 and 2008. 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)	2009		2008		2007
Operating income	$	354.1	$	278.3	$	292.0
Net income	$	200.4	$	143.0	$	161.7

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)	2009		2008		2007
Operating revenues	$	1,751.2	$	1,959.5	$	1,835.1
Cost of goods sold		796.3		1,114.9		1,025.1
Gross margin on revenues		954.9		844.6		810.0
Other operation and maintenance		348.0		351.6		320.7
Depreciation and amortization		187.4		155.0		141.3
Impairment of assets		0.3		---		---
Taxes other than income		65.1		59.7		56.0
Operating income		354.1		278.3		292.0
Interest income		1.1		4.4		---
Allowance for equity funds used during construction		15.1		---		---
Other income		20.4		3.6		5.0
Other expense		6.7		11.8		7.2
Interest expense		93.6		79.1		54.9
Income tax expense		90.0		52.4		73.2
Net income	$	200.4	$	143.0	$	161.7
Operating revenues by classification
Residential	$	717.9	$	751.2	$	706.4
Commercial		439.8		479.0		450.1
Industrial		172.1		219.8		221.4
Oilfield		132.6		151.9		140.9
Public authorities and street light		167.7		190.3		181.4
Sales for resale		53.6		64.9		68.8
Provision for rate refund		(0.6)		(0.4)		0.1
System sales revenues		1,683.1		1,856.7		1,769.1
Off-system sales revenues (A)		31.8		68.9		35.1
Other		36.3		33.9		30.9
Total operating revenues	$	1,751.2	$	1,959.5	$	1,835.1
MWH (B) sales by classification (in millions)
Residential		8.7		9.0		8.7
Commercial		6.4		6.5		6.3
Industrial		3.6		4.0		4.2
Oilfield		2.9		2.9		2.8
Public authorities and street light		3.0		3.0		3.0
Sales for resale		1.3		1.4		1.4
System sales		25.9		26.8		26.4
Off-system sales		1.0		1.4		0.7
Total sales		26.9		28.2		27.1
Number of customers		776,550		770,088		762,234
Average cost of energy per KWH (C) - cents
Natural gas		3.696		8.455		6.872
Coal		1.747		1.153		1.143
Total fuel		2.474		3.337		3.173
Total fuel and purchased power		2.760		3.710		3.523
Degree days (D)
Heating - Actual		3,456		3,394		3,175
Heating - Normal		3,631		3,650		3,631
Cooling - Actual		1,860		2,081		2,221
Cooling - Normal		1,911		1,912		1,911
(A) Sales to other utilities and power marketers. (B) Megawatt-hour. (C) Kilowatt-hour. (D) 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.

2009 compared to 2008. The Company’s operating income increased approximately $75.8 million in 2009 as compared to 2008 primarily due to a higher gross margin partially offset by higher depreciation and amortization expense.

Gross Margin

Gross margin was approximately $954.9 million in 2009 as compared to approximately $844.6 million in 2008, an increase of approximately $110.3 million, or 13.1 percent. The gross margin increased primarily due to:

increased price variance, which included revenues from various rate riders, including the Redbud Facility rider, the storm cost recovery rider, the system hardening rider, the OU Spirit rider and the Oklahoma demand program rider, and higher revenues from the sales and customer mix, which increased the gross margin by approximately $89.5 million;

Ÿ	the $48.3 million Oklahoma rate increase in which the majority of the annual increase is recovered during the summer months, which increased the gross margin by approximately $28.6 million;

Ÿ	revenues from the Arkansas rate increase, which increased the gross margin by approximately $9.3 million;

Ÿ	new customer growth in the Company’s service territory, which increased the gross margin by approximately $8.1 million; and

Ÿ	increased transmission revenues due to higher transmission volumes and increased rates due to the FERC formula rate tariff filing, which increased the gross margin by approximately $1.8 million.

These increases in the gross margin were partially offset by:

Ÿ	milder weather in the Company’s service territory, which decreased the gross margin by approximately $18.2 million; and

Ÿ	lower demand and related revenues by non-residential customers in the Company’s service territory, which decreased the gross margin by approximately $8.1 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 $618.5 million in 2009 as compared to approximately $857.2 million in 2008, a decrease of approximately $238.7 million, or 27.8 percent, primarily due to lower 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 2009, the Company’s fuel mix was 60 percent coal, 38 percent natural gas and two percent wind. In 2008, the Company’s fuel mix was 68 percent coal, 30 percent natural gas and two percent wind. Purchased power costs were approximately $176.6 million in 2009 as compared to approximately $257.0 million in 2008, a decrease of approximately $80.4 million, or 31.3 percent, primarily due to the termination of the purchase power agreement with the Redbud Facility following the Company’s purchase of the Redbud Facility in September 2008 as well as a decrease in purchases in the energy imbalance service market.

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 $348.0 million in 2009 as compared to approximately $351.6 million in 2008, a decrease of approximately $3.6 million, or 1.0 percent. The decrease in other operation and maintenance expenses was primarily due to:

Ÿ	a decrease of approximately $13.2 million in contract technical and construction services attributable to decreased spending on overhauls at some of the Company’s power plants in 2009 as compared to 2008 and utilization of employees instead of contracting external labor;

Ÿ	a decrease 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 in March 2008, as discussed in Note 2 of Notes to Financial Statements;

Ÿ	an increase in capitalized labor in 2009 as compared to 2008, which decreased other operation and maintenance expenses by approximately $7.7 million;

Ÿ	a decrease of approximately $3.8 million in fleet transportation expense primarily due to lower fuel costs in 2009; and

Ÿ	a decrease of approximately $3.2 million due to the reclassification of 2006 and 2007 pension settlement costs to a regulatory asset due to the Arkansas rate case settlement, as discussed in Note 1 of Notes to Financial Statements.

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

Ÿ	an increase of approximately $11.8 million in salaries and wages expense primarily due to salary increases in 2009 and increased incentive compensation expense in 2009;

Ÿ	an increase of approximately $7.2 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider;

Ÿ	an increase of approximately $5.4 million in pension expense;

Ÿ	an increase of approximately $3.3 million due to the Company’s demand-side management initiatives, which expenses are being recovered through a rider;

Ÿ	an increase of approximately $2.2 million in medical and dental expenses; and

Ÿ	an increase of approximately $2.2 million in materials and supplies expense.

Depreciation and amortization expense was approximately $187.4 million in 2009 as compared to approximately $155.0 million in 2008, an increase of approximately $32.4 million, or 20.9 percent, primarily due to additional assets being placed into service, including the Redbud Facility that was placed into service in September 2008, and amortization of several regulatory assets.

Taxes other than income were approximately $65.1 million in 2009 as compared to approximately $59.7 million in 2008, an increase of approximately $5.4 million, or 9.1 percent, primarily due to higher ad valorem taxes.

Additional Information

Interest Income. Interest income was approximately $1.1 million in 2009 as compared to approximately $4.4 million in 2008, a decrease of approximately $3.3 million, or 75.0 percent, primarily due to interest from customers related to the fuel under recovery balance in 2008 and interest income from short-term investments.

Allowance for Equity Funds Used During Construction. AEFUDC was approximately $15.1 million in 2009. There was no AEFUDC in 2008. The increase in AEFUDC was primarily due to construction costs associated with OU Spirit and the Extra High Voltage (“EHV”) Windspeed transmission line being constructed by the Company.

Other Income. Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $20.4 million in 2009 as compared to approximately $3.6 million in 2008, an increase of approximately $16.8 million. Approximately $9.7 million of the increase in other income was related to the benefit associated with the tax gross-up of AEFUDC and approximately $5.9 million of the increase in other income was due to more customers participating in the guaranteed flat bill program and lower than expected usage resulting from milder weather in 2009 as compared to 2008.

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 $6.7 million in 2009 as compared to approximately $11.8 million in 2008, a decrease of approximately $5.1 million, or 43.2 percent, primarily due to 2008 write-downs of approximately $7.7 million for deferred costs associated with the cancelled Red Rock power plant and approximately $1.5 million associated with the 2007 and 2006 storm costs partially offset by an increase in charitable contributions of approximately $3.5 million.

Interest Expense. Interest expense was approximately $93.6 million in 2009 as compared to $79.1 million in 2008, an increase of approximately $14.5 million, or 18.3 percent. The increase in interest expense was primarily due to:

Ÿ	an increase of approximately $29.2 million in interest expense related to the issuances of long-term debt in 2008; and

Ÿ	an increase of approximately $2.0 million in interest expense due to interest to customers related to the fuel over recovery balance in 2009.

These increases in interest expense were partially offset by:

Ÿ	a decrease in interest expense of approximately $8.9 million related to interest on short-term debt primarily due to lower short-term borrowings in 2009 due to the issuances of long-term debt in 2008;

Ÿ	a decrease in interest expense of approximately $4.3 million primarily due to a higher allowance for borrowed funds used during construction for capitalized interest; and

Ÿ	a decrease in interest expense of approximately $2.4 million due to the settlement of treasury lock agreements the Company entered into related to the issuance of long-term debt in January 2008.

Income Tax Expense. Income tax expense was approximately $90.0 million in 2009 as compared to approximately $52.4 million in 2008, an increase of approximately $37.6 million, or 71.8 percent, primarily due to higher pre-tax income in 2009 as compared to 2008, lower Federal investment tax credit amortization and higher state income tax expense.

2008 compared to 2007. The Company’s operating income decreased approximately $13.7 million in 2008 as compared to 2007 primarily due to higher operation and maintenance expense, 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:

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

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

Ÿ	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.

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, 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 in September 2008.

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:

Ÿ	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;

Ÿ	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 in March 2008, as discussed in Note 2 of Notes to Financial Statements;

Ÿ	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;

Ÿ	an increase of approximately $6.6 million in contract technical and construction services expense and approximately $1.5 million in materials and supplies expense primarily attributable to overhaul expenses at several of the Company’s power plants in 2008;

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

Ÿ	an increase of approximately $2.2 million in fleet transportation expense primarily due to higher fuel and maintenance costs in 2008; and

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

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

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

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

Ÿ	a decrease of approximately $3.0 million due to 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, primarily due to additional assets being place into service, including the Redbud Facility that was placed into service in September 2008, and amortization of the Arkansas storm costs that are currently recorded as a regulatory asset.

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 in 2008 and interest income from short-term investments.

Other 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 28.0 percent, primarily due to a lower gain on the guaranteed flat bill tariff due to higher than expected usage resulting from more customers participating in this program.

Other Expense. 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, primarily due to 2008 write-downs of approximately $7.5 million for deferred costs associated with the cancelled Red Rock power plant and approximately $1.5 million associated with the 2007 and 2006 storm costs. These increases in other expense were partially offset by a write-off of approximately $3.1 million associated with the cancelled 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:

Ÿ	an increase of approximately $16.4 million in interest expense related to the issuances of long-term debt in 2008;

Ÿ	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

Ÿ	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 in 2008 as compared to 2007 and an increase in Federal renewable energy credits and additional state income tax credits in 2008 as compared to 2007.

Financial Condition

The balance of Cash and Cash Equivalents was approximately $50.7 million at December 31, 2008 with no balance at December 31, 2009. See “Cash Flows” for a discussion of the changes in Cash and Cash Equivalents.

The balance of Accounts Receivable was approximately $145.9 million and $172.2 million at December 31, 2009 and 2008, respectively, a decrease of approximately $26.3 million, or 15.3 percent, primarily due to a decrease in the Company’s billings to customers from a lower fuel factor in 2009 as compared to 2008 related to lower natural gas prices as well as the Company refunding approximately $80.4 million in fuel clause over recoveries to its Oklahoma customers over the next seven months as discussed below.

The balance of Advances to Parent was approximately $125.9 million at December 31, 2009 with no balance at December 31, 2008. The increase was primarily due to the Company having excess cash due to fuel clause over recoveries and tax benefits related to the 2009 Federal and state tax year as well as return-to-provision adjustments related to the Company’s 2008 Federal and state tax returns.

The balance of Fuel Inventories was approximately $101.0 million and $56.6 million at December 31 2009 and 2008, respectively, an increase of approximately $44.4 million, or 78.4 percent, primarily due to a higher coal inventory balance due to higher average prices and planned outages at one of the Company’s coal-fired power plants.

The balance of Fuel Clause Under Recoveries was approximately $0.3 million and $24.0 million at December 31, 2009 and 2008, respectively, a decrease of approximately $23.7 million, or 98.8 percent, primarily due to the fact that the amount billed to retail customers was higher than the Company’s cost of fuel. The 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.

The balance of Construction Work in Process was approximately $259.9 million and $169.1 million at December 31, 2009 and 2008, respectively, an increase of approximately $90.8 million, or 53.7 percent, primarily due to costs associated with the EHV Windspeed transmission line being constructed by the Company partially offset by the costs associated with OU Spirit being transferred to Property, Plant and Equipment In Service as the individual turbines were placed in service in November and December 2009.

The balance of Accounts Payable – Other was approximately $137.2 million and $105.0 million at December 31, 2009 and 2008, respectively, an increase of approximately $32.2 million, or 30.7 percent, primarily due to an increase in accruals relating to the EHV Windspeed transmission line being constructed by the Company, OU Spirit and an increase in the payable for natural gas purchases.

The balance of Advances from Parent was approximately $17.6 million at December 31, 2008 with no balance at December 31, 2009. See discussion in “Advances to Parent” above for further information.

The balance of Fuel Clause Over Recoveries was approximately $187.5 million and $8.6 million at December 31, 2009 and 2008, respectively, an increase of approximately $178.9 million, primarily due to the fact that the amount billed to retail customers was higher than the Company’s cost of fuel. The 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. As part of the OCC order in the Company’s Oklahoma rate case, the Company will refund approximately $80.4 million in fuel clause over recoveries to its Oklahoma customers over the next seven months.

The balance of Accumulated Deferred Income Taxes was approximately $931.2 million and $722.8 million at December 31, 2009 and 2008, respectively, an increase of approximately $208.4 million, or 28.8 percent, primarily due to accelerated bonus tax depreciation which resulted in higher Federal and state deferred tax accruals.

The balance of Accrued Removal Obligations, Net was approximately $168.2 million and $150.9 million at December 31, 2009 and 2008, respectively, an increase of approximately $17.3 million, or 11.5 percent, primarily due to the net removal accrual exceeding actual removal expense net of salvage.

The balance of Retained Earnings was approximately $1,066.3 million and $865.9 million at December 31, 2009 and 2008, respectively, an increase of approximately $200.4 million, or 23.1 percent. See “Statement of Changes in Stockholder’s Equity” for a discussion of changes in Retained Earnings.

Off-Balance Sheet Arrangement

Railcar Lease Agreement

At December 31, 2009, the Company had a noncancellable operating lease with purchase options, covering 1,462 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. At the end of the 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.

On February 10, 2009, the Company executed a short-term lease agreement for 270 railcars in accordance with new coal transportation contracts with BNSF Railway and Union Pacific. These railcars were needed to replace railcars that have been taken out of service or destroyed. The lease agreement expires with respect to 135 railcars on March 5, 2010. The lease agreement with respect to the remaining 135 railcars expired on November 2, 2009 and was not replaced.

The Company is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to 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. See “Future Sources of Financing – Short-Term Debt” for information regarding the Company’s revolving credit agreement and commercial paper.

The Company’s estimates of capital expenditures are approximately: 2010 - $500 million, 2011 - $555 million, 2012 - $495 million, 2013 - $425 million, 2014 - $350 million and 2015 - $315 million. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s business) plus capital expenditures for known and committed projects (collectively referred to as the “Base Capital Expenditure Plan”). 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		(2010)		(2011-2012)		(2013-2014)		5 years
Capital Expenditures
Base Transmission	$	150.0	$	45.0	$	40.0	$	40.0	$	25.0
Base Distribution		1,320.0		235.0		430.0		435.0		220.0
Base Generation		205.0		30.0		70.0		70.0		35.0
Other		150.0		25.0		50.0		50.0		25.0
Total Base Transmission, Distribution,
Generation and Other		1,825.0		335.0		590.0		595.0		305.0
Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kV)		120.0		30.0		90.0		---		---
Sooner-Rose Hill (345 kV)		65.0		10.0		55.0		---		---
Windspeed (345 kV)		25.0		25.0		---		---		---
Balanced Portfolio 3E Projects		300.0		10.0		170.0		120.0		---
Total Transmission Projects		510.0		75.0		315.0		120.0		---
Other Projects:
Smart Grid Program (A)		230.0		40.0		120.0		60.0		10.0
System Hardening		35.0		20.0		15.0		---		---
OU Spirit		10.0		10.0		---		---		---
Other		30.0		20.0		10.0		---		---
Total Other Projects		305.0		90.0		145.0		60.0		10.0
Total Known and Committed Projects		815.0		165.0		460.0		180.0		10.0
Total capital expenditures (B)		2,640.0		500.0		1,050.0		775.0		315.0
Maturities of long-term debt		1,545.4		---		---		---		1,545.4
Total capital requirements		4,185.4		500.0		1,050.0		775.0		1,860.4

Operating lease obligations
Railcars		41.9		3.9		38.0		---		---

Other purchase obligations and commitments
Cogeneration capacity payments		406.0		86.1		164.2		155.7		N/A
Fuel minimum purchase commitments		426.0		340.0		84.2		1.8		---
Wind minimum purchase commitments		948.9		10.2		103.3		104.8		730.6
Long-term service agreement commitments		141.3		3.7		28.4		37.9		71.3
Total other purchase obligations and
commitments		1,922.2		440.0		380.1		300.2		801.9

Total capital requirements, operating lease
obligations and other purchase obligations
and commitments		6,149.5		943.9		1,468.1		1,075.2		2,662.3
Amounts recoverable through fuel adjustment
clause (C)		(1,822.8)		(440.2)		(389.7)		(262.3)		(730.6)
Total, net	$	4,326.7	$	503.7	$	1,078.4	$	812.9	$	1,931.7

(A) These capital expenditures are contingent upon OCC approval of the Company’s Positive Energy Smart Grid program and are net of the Smart Grid $130 million grant approved by the DOE.

(B) The Base Capital Expenditure Plan above excludes any environmental expenditures associated with Best Available Retrofit Technology (“BART”) requirements due to the uncertainty regarding BART costs. As discussed in “– Environmental Laws and Regulations” below, pursuant to a proposed regional haze agreement the Company has agreed to install low nitrogen oxide (“NOX”) burners and related equipment at the three affected generating stations. Preliminary estimates indicate the cost will be approximately $100 million (plus or minus 30 percent). For further information, see “– Environmental Laws and Regulations” below.

(C) Includes expected recoveries of costs incurred for the Company’s railcar operating lease obligations, the Company’s cogeneration capacity payments, the Company’s unconditional fuel purchase obligations and the Company’s wind purchase commitments.

N/A – not available

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in transmission assets and wind generation assets, will be evaluated based upon their impact upon achieving the Company’s financial objectives.

The Company also has approximately 720 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.

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.

2009 Capital Requirements and Financing Activities

Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were approximately $600.5 million in 2009. There were no contractual obligations, net of recoveries through fuel adjustment clauses in 2009. Approximately $1.3 million of the 2009 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $890.2 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. During 2009, the Company’s sources of capital were cash generated from operations and proceeds from the issuance of short-term debt. 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.

Long-Term Debt Maturities

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

Net Available Liquidity

At December 31, 2009, the Company had less than $0.1 million in cash and cash equivalents. At December 31, 2009, the Company had approximately $378.8 million of net available liquidity under its revolving credit agreement.

Cash Flows

Year Ended December 31 (In millions)	2009		2008		2007
Net cash provided from operating activities	$	580.2	$	206.4	$	230.1
Net cash used in investing activities		(599.5)		(839.6)		(376.4)
Net cash (used in) provided from financing activities		(31.4)		683.9		146.3

The increase of approximately $373.8 million in net cash provided from operating activities in 2009 as compared to 2008 was primarily due to:

Ÿ	higher fuel recoveries in 2009 as compared to 2008;

Ÿ	cash received in 2009 from the implementation of the Redbud Facility rider in the third quarter of 2008;

Ÿ	cash received in 2009 from the implementation of the Oklahoma rate increase in August 2009; and

Ÿ	payments made by the Company in the first quarter of 2008 related to the December 2007 ice storm.

The decrease of approximately $23.7 million in net cash provided from operating activities in 2008 as compared to 2007 was primarily due to payments made by the Company in the first quarter of 2008 related to the December 2007 ice storm. This decrease in net cash provided from operating activities was partially offset by:

Ÿ	higher fuel recoveries in 2008 as compared to 2007; and

Ÿ	higher billed sales in 2008.

The decrease of approximately $240.1 million in net cash used in investing activities in 2009 as compared to 2008 primarily related to higher levels of capital expenditures in 2008 mostly related to the purchase of the Redbud Facility in September 2008 partially offset by capital expenditures in 2009 related to OU Spirit and the EHV Windspeed transmission line being constructed by the Company. 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 mostly related to the purchase of the Redbud Facility in September 2008.

The decrease of approximately $715.3 million in net cash provided from financing activities in 2009 as compared to 2008 was primarily due to:

Ÿ	proceeds received from the issuances of $700 million in long-term debt in 2008; and

Ÿ	a capital contribution from OGE Energy to fund a portion of the purchase of the Redbud Facility in 2008.

These decreases in net cash provided from financing activities were partially offset by a decrease in short-term debt primarily due to proceeds received from the issuances of long-term debt which were used to repay short-term borrowings in 2008.

The increase of approximately $537.6 million in net cash provided from financing activities in 2008 as compared to 2007 primarily related to:

Ÿ	proceeds received from the issuances of $700 million in long-term debt in 2008; and

Ÿ	a capital contribution from OGE Energy to fund a portion of the purchase of the Redbud Facility in 2008.

These increases in net cash provided from financing activities were partially offset by a decrease in short-term debt primarily due to proceeds received from the issuances of long-term debt which were used to repay short-term borrowings in 2008.

Future Capital Requirements

Pension and Postretirement Benefit Plans

1, 2000 participate in defined benefit postretirement plans. See Note 11 of Notes to Financial Statements for a further discussion.

At December 31, 2009, approximately 49.4 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 2009, asset returns on the Pension Plan increased approximately 22.9 percent from a decrease of approximately 25.1 percent in 2008 due to the decline in the equity market in 2008. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future. During each of 2009 and 2008, 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. The level of funding is dependent on returns on plan assets and future discount rates. During 2010, 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.

OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. 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 retirement restoration expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions)	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 and Arkansas jurisdictional portion of these changes were recorded as a regulatory asset (see Note 1 of Notes to Financial Statements for a further discussion).

At December 31, 2009, 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 $478.2 million and $398.9 million, respectively, for an underfunded status of approximately $79.3 million. Also, at December 31, 2009, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $232.5 million and $52.5 million, respectively, for an underfunded status of approximately $180.0 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 benefit cost to be recognized in the Statements of Income in future periods.

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 benefit 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 or advances from OGE Energy generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper, by borrowings under its revolving credit agreement or by advances from OGE Energy. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2009 or 2008. At December 31, 2009, the Company had no outstanding advances from OGE Energy. At December 31, 2008, the Company had approximately $17.6 million in outstanding advances from OGE Energy. The following table provides information regarding OGE Energy’s and the Company’s revolving credit agreements and available cash at December 31, 2009.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding		Interest Rate	Maturity
OGE Energy	$	596.0	$	175.0	0.27%	December 6, 2012
The Company		389.0		10.2	0.14%	December 6, 2012
		985.0		185.2	0.26%
Cash		---		N/A	N/A	N/A
Total	$	985.0	$	185.2	0.26%

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

Registration Statement Filing

During the first half of 2010, the Company expects to file a Form S-3 Registration Statement to register debt securities for sale by the Company.

Expected Issuance of Long-Term Debt

Income Tax Refund

As discussed in Note 7 of Notes to Financial Statements, the Company filed a request with the IRS on December 29, 2008 for a change in its tax method of accounting related to the capitalization of repair expenditures. On December 10, 2009, the Company received approval from the IRS for the change in accounting method. In December 2009, a claim for refund was filed to carry back the 2008 tax loss resulting in a tax refund of approximately $88.6 million, which the Company received in February 2010. The expected refund was recorded as an intercompany receivable on the Balance Sheet at December 31, 2009.

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 a Pension Plan that covers substantially all of the Company’s employees hired before December 1, 2009. Also, effective December 1, 2009, OGE Energy’s Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover substantially all of its 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 11 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	+/- $24.8 million
Discount rate	+/- 0.25 percent	+/- $19.4 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 12 and 13 of Notes to Financial Statements and Item 3 in this Form 10-K.

Asset Retirement Obligations

In the fourth quarter of 2009, the Company recorded an ARO for approximately $4.5 million related to its OU Spirit wind farm. Beginning January 1, 2010, the Company will amortize the remaining value of the related ARO asset over the estimated remaining life of 35 years. The Company also has other previously recorded AROs that are being amortized over their respective lives ranging from 20 to 99 years. The Company also has 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 hedge transactions to manage commodity risk. The Company may hedge its forward exposure to manage the impact of changes in commodity prices. Hedges of anticipated transactions are documented as cash flow hedges and are executed based upon management-established price targets. During 2009, the Company applied hedge accounting to manage its natural gas exposure associated with a wholesale generation sales contract, which hedge expires in 2013. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings.

The Company engages in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 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. These treasury lock agreements qualified as cash flow hedges with an objective to protect against the variability of future interest payments of long-term debt that was issued by the Company. The Company does not currently have any outstanding treasury lock agreements.

Regulatory Assets and Liabilities

The Company, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which 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 benefits obligation regulatory asset is comprised of items which are probable of future recovery that have not yet been recognized as a component of net periodic benefit cost including, net loss, prior service cost and net transition obligation.

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, 2009, 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 $0.4 million. At December 31, 2009 and 2008, Accrued Unbilled Revenues were approximately $57.2 million and $47.0 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. Beginning in August 2009 and going forward, there was a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel will be recovered through the fuel adjustment clause. At December 31, 2009, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of approximately $0.2 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 $1.7 million and $2.3 million at December 31, 2009 and 2008, respectively.

Accounting Pronouncements

See Notes to Financial Statements for a discussion of accounting principles that are applicable to the Company.

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 12 and 13 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.

Environmental Laws and Regulations

The activities of the Company are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including 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 can impose burdensome 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 (“Federal Clean Water Act”) and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes.

Environmental regulation can increase the cost of planning, design, initial installation and operation of 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 $1.9 million and $2.3 million, respectively of the Company’s capital expenditures budgeted for 2010 and 2011 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 associated with environmental quality will be approximately $20.9 million during 2010 as compared to approximately $19.9 million in 2009. 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

Federal Clean Air Act

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.

Mercury and Hazardous Air Pollutants

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. In January 2010, the EPA issued an information collection request which will survey power plant operators about their emissions of mercury and other hazardous air pollutants (“HAP”). The EPA has announced plans to promulgate new HAP emission limitations for coal-fired and oil-fired power plants by November 2011. Any costs associated with future regulation of mercury or other HAPs are uncertain at this time. Because of the uncertainty caused by the litigation regarding the CAMR, the promulgation of an Oklahoma rule that would have applied to existing facilities has also been delayed. The Company will continue to participate in the state rule making process.

RICE MACT Amendments

On March 5, 2009, the EPA initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing amendments to the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engine Maximum Achievable Control Technology (“RICE MACT Amendments”). Depending on the final regulations that may be enacted by the EPA for the RICE MACT Amendments, Company facilities will likely be impacted. The costs that may be incurred to comply with these regulations, including the testing and modification of the affected engines, are uncertain at this time. The current proposed compliance deadline is three years from the effective date of the final rules.

Regional Haze

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 joined with eight other central states to address these visibility impacts.

The Company was required to evaluate the installation of BART to address regional haze at sources built between 1962 and 1977. The Oklahoma Department of Environmental Quality (“ODEQ”) made a preliminary determination to accept an application for a waiver from BART requirements for the Horseshoe Lake generating station based on modeling showing no significant impact on visibility in nearby Class I areas. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan (“SIP”) for regional haze.

Waivers were not available for the BART-eligible 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 NOX controls on all three units. On May 30, 2008, the Company filed BART evaluations for the affected generating units at the Muskogee and Sooner generating stations. In this 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 the four coal-fired generating units at its Muskogee and Sooner generating stations. The Company did not propose the installation of scrubbers

at these 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 more than $1.0 billion) would not be cost-effective. The original deadline for the ODEQ to submit a SIP 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 SIP. If the ODEQ fails to meet this deadline, the EPA can issue a Federal implementation plan. The draft SIP was published by the ODEQ for public review on November 13, 2009. This draft SIP suggested that scrubbers would be needed to comply with the regional haze regulations, but noted the Company’s cost-effectiveness analysis. Following negotiations with the ODEQ, the Company submitted in February 2010 a proposed agreement to the ODEQ (the “Proposed Agreement”) which specifies that BART for reducing NOX emissions at all seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations should be the installation of low NOX burners with overfire air (and flue gas recirculation on two of the affected units) and accompanying emission rate and annual emission tonnage limits. Preliminary estimates based on recent industry experience and cost projections estimate the total cost of the NOX-related equipment at the three affected generating stations at approximately $100 million (plus or minus 30 percent). After the Company obtains estimates from vendors based on a detailed engineering design, it will have a more firm estimate of the exact cost of the NOX-related equipment subject to changes in the cost of basic materials. Under the Proposed Agreement, the specified BART for reducing sulfur dioxide (“SO2”) at the four coal-fired units at the Muskogee and Sooner generating stations would be continued use of low sulfur coal and emission rate and annual emission tonnage limits consistent with such use of low sulfur coal. Implementation of these BART requirements would be achieved within five years of the EPA’s approval of Oklahoma’s regional haze SIP.

Under the Proposed Agreement, there also would be an alternative compliance obligation in the event that the EPA disapproves the aforementioned BART determination and the underlying conclusion that dry flue gas desulfurization units with Spray Dryer Absorber (“Dry Scrubbers”) are not cost-effective. In such an event, and only after the Company has exhausted all judicial and administrative appeals of the EPA disapproval, the Company would have two options. First, the Company could choose to install Dry Scrubbers (or meet the corresponding SO2 emissions limits associated with Dry Scrubbers) by January 1, 2018. Second, the Company could choose to comply with the regional haze regulations by implementing a fuel switching alternative. This alternative would require the Company to achieve a combined annual SO2 emission limit by December 31, 2026 that is equivalent to: (i) the SO2 emission limits associated with installing and operating Dry Scrubbers on two of the BART-eligible coal fired units and (ii) being at or below the SO2 emissions that would result from switching the other two coal-fired units to natural gas. If the Company has elected to comply with this alternative and if, prior to January 1, 2022, any of these units is required by any environmental law other than the regional haze rule to install flue gas desulfurization equipment or achieve an SO2 emissions rate lower than 0.10 lbs/MMBtu, and if the Company proceeds to take all necessary steps to comply with such legal requirement, the enforceable emission limits in the operating permits for the affected coal units would be adjusted to reflect the installation of that equipment or the emission rates specified under such legal requirement and the Company would no longer be required to undertake the 2026 emission levels.

The Company expects that the ODEQ will sign the Proposed Agreement and will include the agreement in the final SIP that is submitted to the EPA for approval. It is anticipated that the EPA will take final action on the SIP for regional haze during the first quarter of 2011. The Company cannot predict what action the EPA will take.

Until the EPA takes final action on the regional haze SIP, 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 expenditures for the installation of emission control equipment 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.

Sulfur Dioxide

The 1990 Federal Clean Air Act includes an acid rain program to reduce 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 2009, the Company’s SO2 emissions were below the allowable limits.

On November 16, 2009, the EPA proposed a new one-hour National Ambient Air Quality Standard (“NAAQS”) for SO2 to address public health concerns. The EPA is proposing to revise the primary SO2 standard to a level of between 50 and 100 parts per billion (“PPB”) measured over one-hour. The EPA is under a consent decree to take final action by June 2, 2010. The proposal was published in the Federal Register on December 8, 2009. Oklahoma is in attainment with the current three-hour and 24-hour SO2 NAAQS; however, a one-hour standard less than 100 PPB may result in certain areas not meeting attainment. 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.

Ozone

On January 7, 2010, the EPA announced a proposal to set the “primary” standard for ozone at a level between 0.06 and 0.07 parts per million measured over eight hours. The EPA is also proposing to set a separate “secondary” standard to protect the environment, especially plants and trees. The deadline for submitting comments on the proposal is March 22, 2010. The EPA has also proposed an accelerated schedule for designating areas for the primary ozone standard and is accepting comments on whether to designate areas for a seasonal secondary standard on an accelerated schedule or a two-year schedule. Following area designations by the EPA, expected to become effective August 2011, the proposed schedule would require submittal by December 2013 of state implementation plans that outline how the state will reduce pollution to meet the ambient standard. The state would be required to meet the primary standard, with deadlines depending on the severity of the problem, between 2014 and 2031. The Company cannot predict the final outcome of this evaluation or its timing or affect on its operations.

Greenhouse Gases

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 and regulation at the Federal level, actions at the state level, litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. Recently, two Federal courts of appeal have reinstated nuisance-type claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. Although the Company is not a defendant in either proceeding, additional litigation in Federal and state courts over these issues is expected.

Legislation

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. Enogex is a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Water

Section 316(b) of the Federal Clean Water Act requires that the locations, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions addressing previous rules and confirming that EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. On January 7, 2008, the Company submitted to the state of Oklahoma a comprehensive demonstration study for each affected facility. At the Company’s request, Oklahoma will not require implementation of 316(b) requirements prior to the EPA developing and finalizing their rules. When there are final rules implemented by the state, the Company may require additional capital and/or increased operating costs associated with cooling water intake structures at its generating facilities.

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, 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 OGE Energy’s Board of Directors.

The Company also has a Corporate Risk Management Department led by the Company’s 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 OGE Energy’s Board of Directors and senior executives of the Company with confidence that the risks taken on by the Company’s business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to risk management are being followed. Some of the measures in these policies include value-at-risk 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, treasury lock agreements and commercial paper. The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, 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 fair value of the Company’s long-term debt is based on quoted market prices. At December 31, 2009 and 2008, the Company had no outstanding treasury lock 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							12/31/09
(Dollars in millions)	2014				Total			Fair Value
Fixed-rate debt (A)
Principal amount		$	1,410.0		$	1,410.0		$	1,492.1
Weighted-average
interest rate			6.63	%		6.63	%		---
Variable-rate debt (B)
Principal amount		$	135.4		$	135.4		$	135.4
Weighted-average
interest rate			0.57	%		0.57	%		---

(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. 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 treatment to: (i) electric power contracts by the Company and (ii) fuel procurement by the Company.

Item 8. Financial Statements and Supplementary Data.


OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME

Year ended December 31 (In millions)	2009		2008		2007
OPERATING REVENUES	$	1,751.2	$	1,959.5	$	1,835.1

COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)		796.3		1,114.9		1,025.1
Gross margin on revenues		954.9		844.6		810.0
Other operation and maintenance		348.0		351.6		320.7
Depreciation and amortization		187.4		155.0		141.3
Impairment of assets		0.3		---		---
Taxes other than income		65.1		59.7		56.0

OPERATING INCOME		354.1		278.3		292.0

OTHER INCOME (EXPENSE)
Interest income		1.1		4.4		---
Allowance for equity funds used during construction		15.1		---		---
Other income		20.4		3.6		5.0
Other expense		(6.7)		(11.8)		(7.2)
Net other income (expense)		29.9		(3.8)		(2.2)

INTEREST EXPENSE
Interest on long-term debt		96.5		67.3		50.9
Allowance for borrowed funds used during construction		(8.3)		(4.0)		(4.0)
Interest on short-term debt and other interest charges		5.4		15.8		8.0
Interest expense		93.6		79.1		54.9

INCOME BEFORE TAXES		290.4		195.4		234.9

INCOME TAX EXPENSE		90.0		52.4		73.2

NET INCOME	$	200.4	$	143.0	$	161.7

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

OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS

December 31 (In millions)	2009		2008

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	---	$	50.7
Accounts receivable, less reserve of $1.7 and $2.3, respectively		145.9		172.2
Accrued unbilled revenues		57.2		47.0
Advances to parent		125.9		---
Fuel inventories		101.0		56.6
Materials and supplies, at average cost		73.5		67.4
Gas imbalances		0.1		0.6
Accumulated deferred tax assets		23.8		12.7
Fuel clause under recoveries		0.3		24.0
Prepayments		8.5		8.0
Other		7.6		2.3
Total current assets		543.8		441.5

OTHER PROPERTY AND INVESTMENTS, at cost		2.9		3.6

PROPERTY, PLANT AND EQUIPMENT
In service		6,623.7		6,101.1
Construction work in progress		259.9		169.1
Total property, plant and equipment		6,883.6		6,270.2
Less accumulated depreciation		2,416.0		2,314.7
Net property, plant and equipment		4,467.6		3,955.5

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		19.1		14.6
Benefit obligations regulatory asset		357.8		344.7
McClain Plant deferred expenses		---		6.2
Unamortized loss on reacquired debt		16.5		17.7
Unamortized debt issuance costs		10.8		11.4
Other		59.6		56.0
Total deferred charges and other assets		463.8		450.6

TOTAL ASSETS	$	5,478.1	$	4,851.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)

December 31 (In millions)	2009		2008

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	4.6	$	6.4
Accounts payable - other		137.2		105.0
Advances from parent		---		17.6
Customer deposits		60.1		56.8
Accrued taxes		29.1		27.9
Accrued interest		40.4		33.2
Accrued compensation		26.3		25.1
Fuel clause over recoveries		187.5		8.6
Other		20.2		26.8
Total current liabilities		505.4		307.4

LONG-TERM DEBT		1,541.8		1,541.4

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		261.0		261.9
Accumulated deferred income taxes		931.2		722.8
Accumulated deferred investment tax credits		13.1		17.3
Accrued removal obligations, net		168.2		150.9
Price risk management		0.7		---
Other		32.4		25.2
Total deferred credits and other liabilities		1,406.6		1,178.1

Total liabilities		3,453.8		3,026.9

COMMITMENTS AND CONTINGENCIES (NOTE 12)

STOCKHOLDER’S EQUITY
Common stockholder’s equity		958.4		958.4
Retained earnings		1,066.3		865.9
Accumulated other comprehensive loss, net of tax		(0.4)		---
Total stockholder’s equity		2,024.3		1,824.3

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	5,478.1	$	4,851.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION

December 31 (In millions)			2009		2008

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		857.5
Retained earnings				1,066.3		865.9
Accumulated other comprehensive loss, net of tax				(0.4)		---
Total stockholder’s equity				2,024.3		1,824.3

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		250.0
8.25%	Senior Notes, Series Due January 15, 2019			250.0		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		200.0
Other Bonds
0.30% - 1.00%	Garfield Industrial Authority, January 1, 2025			47.0		47.0
0.42% - 0.74%	Muskogee Industrial Authority, January 1, 2025			32.4		32.4
0.42% - 0.75%	Muskogee Industrial Authority, June 1, 2027			56.0		55.9

Unamortized discount				(3.6)		(3.9)
Total long-term debt				1,541.8		1,541.4

Total Capitalization			$	3,566.1	$	3,365.7

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, 2006	$	100.9	$	564.5	$	656.0	$	0.6	$	1,322.0
Comprehensive income (loss)
Net income for 2007		---		---		161.7		---		161.7
Other comprehensive loss, 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 (loss)		---		---		161.7		(0.6)		161.1
Dividends declared on common stock		---		---		(56.0)		---		(56.0)
Adoption of new accounting principle (($6.2) pre-tax) (A)		---		---		(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 OGE Energy		---		293.0		---		---		293.0
Balance at December 31, 2008	$	100.9	$	857.5	$	865.9	$	---	$	1,824.3
Comprehensive income
Net income for 2009		---		---		200.4		---		200.4
Other comprehensive loss, net of tax
Deferred hedging losses, net of tax (($0.7) pre-tax)		---		---		---		(0.4)		(0.4)
Other comprehensive loss		---		---		---		(0.4)		(0.4)
Comprehensive income (loss)		---		---		200.4		(0.4)		200.0
Balance at December 31, 2009	$	100.9	$	857.5	$	1,066.3	$	(0.4)	$	2,024.3

(A) The Company recognized a cumulative effect adjustment for its uncertain tax positions on January 1 2007 related to the adoption of a new accounting principle.

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)	2009		2008		2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	200.4	$	143.0	$	161.7
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation and amortization		187.4		155.0		141.3
Impairment of assets		0.3		---		---
Deferred income taxes and investment tax credits, net		202.8		87.2		3.6
Allowance for equity funds used during construction		(15.1)		---		---
Loss on disposition and abandonment of assets		0.6		---		3.8
Write-down of regulatory assets		---		9.2		---
Price risk management assets		---		---		0.9
Price risk management liabilities		0.7		(1.7)		1.7
Other assets		22.0		1.6		(12.7)
Other liabilities		(72.8)		(30.0)		(53.4)
Change in certain current assets and liabilities
Accounts receivable, net		26.3		(37.3)		3.3
Accrued unbilled revenues		(10.2)		(1.3)		(6.0)
Fuel, materials and supplies inventories		(50.5)		(19.8)		(19.6)
Gas imbalance assets		0.5		(0.5)		(0.1)
Fuel clause under recoveries		23.7		3.3		(27.3)
Other current assets		(4.8)		(2.3)		1.5
Accounts payable		(2.4)		(59.3)		69.1
Accounts payable - affiliates		(1.8)		(4.1)		5.3
Income taxes payable - affiliates		(112.1)		(64.2)		44.3
Customer deposits		3.3		3.2		2.7
Accrued taxes		1.2		3.0		0.8
Accrued interest		7.2		11.7		(6.9)
Accrued compensation		1.2		(3.7)		4.6
Fuel clause over recoveries		178.9		4.4		(92.1)
Other current liabilities		(6.6)		9.0		3.6
Net Cash Provided from Operating Activities		580.2		206.4		230.1
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(600.5)		(840.1)		(377.3)
Proceeds from sale of assets		1.0		0.5		0.9
Net Cash Used in Investing Activities		(599.5)		(839.6)		(376.4)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt, net		(31.5)		(267.0)		202.4
Proceeds from long-term debt		0.1		743.0		---
Capital contribution from OGE Energy		---		293.0		---
Dividends paid on common stock		---		(35.0)		(56.0)
Retirement of long-term debt		---		(50.1)		(0.1)
Net Cash (Used in) Provided from Financing Activities		(31.4)		683.9		146.3
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(50.7)		50.7		---
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		50.7		---		---
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

Basis of Presentation

In the opinion of management, all adjustments necessary to fairly present the financial position of the Company at December 31, 2009 and 2008, the results of its operations and the results of its cash flows for the years ended December 31, 2009, 2008 and 2007, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of subsequent events for inclusion in the Company’s Financial Statements occurring after December 31, 2009 through February 17, 2010, the date the Company’s financial statements were issued, and, in the opinion of management, the Company’s Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

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 accounting principles for certain types of rate-regulated activities, which provide 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 (In millions)	2009			2008
Regulatory Assets
Benefit obligations regulatory asset	$	357.8	$		344.7
Deferred storm expenses		28.0			32.2
Income taxes recoverable from customers, net		19.1			14.6
Deferred pension plan expenses		18.1			14.6
Unamortized loss on reacquired debt		16.5			17.7
Red Rock deferred expenses		7.7			7.4
Fuel clause under recoveries		0.3			24.0
McClain Plant deferred expenses		---			6.2
Miscellaneous		3.9			2.9
Total Regulatory Assets	$	451.4	$		464.3

Regulatory Liabilities
Fuel clause over recoveries	$	187.5	$		8.6
Accrued removal obligations, net		168.2			150.9
Miscellaneous		7.3			4.9
Total Regulatory Liabilities	$	363.0	$		164.4

The benefit obligations regulatory asset is comprised of items which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost including, net loss, prior service cost and net transition obligation. For companies not subject to accounting principles for certain types of rate-regulated activities, these charges were required to be included in Accumulated Other Comprehensive Income. However, for companies subject to accounting principles for certain types of rate-regulated activities, 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 benefit obligations regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

The following table is a summary of the components of the benefit obligations regulatory asset at:

December 31 (In millions)	2009		2008
Defined benefit pension plan and restoration of retirement income plan:
Net loss	$	222.8	$	259.8
Prior service cost		12.5		3.5
Defined benefit postretirement plans:
Net loss		114.9		70.4
Net transition obligation		7.6		10.2
Prior service cost		---		0.8
Total	$	357.8	$	344.7

The following amounts in the benefit obligations regulatory asset at December 31, 2009 are expected to be recognized as components of net periodic benefit cost in 2010:

(In millions)
Defined benefit pension plan and restoration of retirement income plan:
Net loss	$	15.9
Prior service cost		2.7
Defined benefit postretirement plans:
Net loss		9.1
Net transition obligation		2.5
Total	$	30.2

In accordance with the September 2008 OCC rate order, the Company was allowed to defer the Oklahoma storm-related operation and maintenance expenses in excess of $2.7 million and will reserve for any Oklahoma storm-related expenses less than $2.7 million. The Company will recover the deferred amounts over a five-year period ending in August 2013.

Income taxes recoverable from customers, which represents income tax benefits previously used to reduce the Company’s revenues, are treated as regulatory assets and liabilities and are being amortized over the estimated remaining life of the assets to which they relate. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. 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.”

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. These deferred amounts have been recorded as a regulatory asset as the Company received an order in July 2009 allowing it to begin recovery of approximately $16.8 million of these costs over a four-year period. In accordance with the APSC order received by the Company in May 2009 in its Arkansas rate case, the Company was allowed recovery of its 2006 and 2007 pension settlement costs. During the second quarter of 2009, the Company reduced its pension expense and recorded a regulatory asset for approximately $3.2 million, which will be amortized over approximately a 10-year period, as allowed in the Arkansas rate order. Both the Oklahoma and Arkansas pension plan expenses are reflected in Deferred Pension Plan Expenses in the table above.

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.

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. As part of the OCC order in the Company’s Oklahoma rate case, the Company will refund approximately $80.4 million in fuel clause over recoveries to its Oklahoma customers over the next seven months.

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

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

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for the Company 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. Beginning in August 2009 and going forward, there was a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel will be recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable was approximately $1.7 million and $2.3 million at December 31, 2009 and 2008, 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. The Company uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was approximately $101.0 million and $56.6 million at December 31, 2009 and 2008, respectively.

Property, Plant and Equipment

All property, plant and equipment is 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 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 tables present the Company’s ownership interest in the jointly-owned 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (“McClain Plant”) and the jointly-owned 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“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 these tables. 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
December 31, 2009 (In millions)	Ownership	and Equipment			Depreciation			and Equipment
McClain Plant	77	$	197.7		$	55.3		$	142.4
Redbud Facility	51	$	523.3	(A)	$	80.3	(B)	$	443.0
(A) This amount includes a plant acquisition adjustment of approximately $148.3 million.
(B) This amount includes accumulated amortization of the plant acquisition adjustment of approximately $6.9 million.
	Percentage	Total Property, Plant			Accumulated			Net Property, Plant
December 31, 2008 (In millions)	Ownership	and Equipment			Depreciation			and Equipment
McClain Plant	77	$	181.0		$	44.6		$	136.4
Redbud Facility	51	$	496.6	(C)	$	63.9	(D)	$	432.7
(C) This amount includes a plant acquisition adjustment of approximately $153.7 million.
(D) This amount includes accumulated amortization of the plant acquisition adjustment of approximately $1.5 million.

The Company’s property, plant and equipment and related accumulated depreciation are divided into the following major classes at:

	Total Property,				Net Property,
	Plant and		Accumulated		Plant and
December 31, 2009 (In millions)	Equipment		Depreciation		Equipment
Distribution assets	$	2,676.2	$	861.1	$	1,815.1
Electric generation assets		2,878.2		1,141.5		1,736.7
Transmission assets		1,071.6		310.1		761.5
Intangible plant		29.7		22.6		7.1
Other property and equipment		227.9		80.7		147.2
Total property, plant and equipment	$	6,883.6	$	2,416.0	$	4,467.6

	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

Depreciation and Amortization

The provision for depreciation, which was approximately 2.9 percent and 2.7 percent, respectively, of the average depreciable utility plant for 2009 and 2008, 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 2010, the provision for depreciation is projected to be approximately 2.9 percent of the average depreciable utility plant. Amortization of intangibles is computed using the straight-line method. Approximately 71.4 percent of the remaining amortizable intangible plant balance at December 31, 2009 will be amortized over three years with approximately 28.6 percent of the remaining amortizable intangible plant balance at December 31, 2009 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 of the acquired asset. Plant acquisition adjustments include approximately $148.3 million for the Redbud Facility, which are being amortized over a 27-year life and approximately $3.1 million for certain substation facilities in the Company’s service territory, which are being amortized over a 26 to 59-year period.

Asset Retirement Obligations

In the fourth quarter of 2009, the Company recorded an ARO for approximately $4.5 million related to its OU Spirit wind project in western Oklahoma (“OU Spirit”). Beginning January 1, 2010, the Company will amortize the remaining value of the related ARO asset over the estimated remaining life of 35 years. The Company also has other previously recorded AROs that are being amortized over their respective lives ranging from 20 to 99 years. The Company also has 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 7.99 percent, 3.58 percent and 5.78 percent for the years 2009, 2008 and 2007, respectively. The increase in the AFUDC rates in 2009 was primarily due to the lack of short-term borrowings in conjunction with a high level of capital spending.

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

SPP Purchases and Sales

The Company participates in the Southwest Power Pool (“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.

Accumulated Other Comprehensive Loss

There was approximately $0.4 million in accumulated other comprehensive loss at December 31, 2009 related to deferred hedging activity. There was no accumulated other comprehensive income balance at December 31, 2008.

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 have been designated as one of several potentially responsible parties, the amount accrued represents the Company’s estimated share of the cost. The Company has less than $0.1 million in accrued environmental liabilities at both December 31, 2009 and 2008.

Related Party Transactions

OGE Energy charged operating costs to the Company of approximately $92.6 million, $87.4 million and $96.4 million in 2009, 2008 and 2007, respectively. OGE Energy charges 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 2009, 2008 and 2007, the Company recorded an expense from its affiliate, Enogex LLC and its subsidiaries (“Enogex”), of approximately $34.8 million, $34.8 million and $34.7 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In 2009, 2008 and 2007, the Company recorded an expense from Enogex of approximately $12.7 million, $12.8 million and $12.7 million, respectively, for natural gas storage services. In 2009, 2008 and 2007, the Company also recorded natural gas purchases from its affiliate, OGE Energy Resources, Inc. (“OERI”) of

approximately $38.5 million, $79.6 million and $55.2 million, respectively. Approximately $4.7 million and $6.6 million were recorded at December 31, 2009 and 2008, respectively, and are included in Accounts Payable – Affiliates in the Balance Sheet for these activities.

On July 1, 2009, the Company, Enogex and OERI entered into hedging transactions to offset natural gas length positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority (“OMPA”). Enogex sold physical natural gas to OERI, and the Company entered into an offsetting natural gas swap with OERI. These transactions are for approximately 50,000 million British thermal units (“MMBtu”) per month from August 2009 to December 2013 (see Note 3 for a further discussion).

In 2009, 2008 and 2007, the Company recorded interest income of less than $0.1 million for advances made to OGE Energy from the Company.

In 2009, 2008 and 2007, the Company recorded interest expense of approximately $0.1 million, $2.1 million and $6.1 million, respectively, 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 2009, the Company declared no dividends to OGE Energy. In 2008 and 2007, the Company declared dividends of approximately $35.0 million and $56.0 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 Pronouncements and Developments

In December 2008, the Financial Accounting Standards Board (“FASB”) issued “Employer’s Disclosures about Postretirement Benefit Plan Assets,” which amends previously issued accounting guidance in this area. The new standard applies to employers with defined benefit pension or other postretirement benefit plans. The new standard requires additional disclosures related to: (i) investment policies and strategies, (ii) categories of plan assets, (iii) fair value measurement of plan assets and (iv) significant concentrations of risk. The new standard is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Upon initial application, prior periods are not required to be presented for comparative purposes. The Company adopted this new standard effective December 31, 2009 and has presented the additional disclosures in Note 11.

In December 2009, the FASB issued “Consolidations – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amends previously issued accounting guidance in this area. The new standard applies to entities involved with variable interest entities (“VIE”). The new standard changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. The new standard requires additional disclosures related to: (i) an entity’s involvement with VIE’s and (ii) any significant changes in risk exposure due to that involvement. The new standard is effective for fiscal years beginning after November 15, 2009, and interim periods following initial adoption, with earlier application prohibited. Upon initial application, prior periods are not required to be presented for comparative purposes. The Company adopted this new standard effective January 1, 2010. The adoption of this new standard did not have a material impact on the Company’s financial position or results of operations.

In January 2010, the FASB issued “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements,” which requires new disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in previously issued accounting guidance in this area. The new standard requires additional disclosures related to: (i) the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers and (ii) presenting separate information about purchases, sales, issuances and settlements (on a gross basis) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3). Also, the new standard clarifies the requirements of previously issued accounting guidance in this area related to: (i) a reporting entity’s need to use judgment in determining the appropriate classes of assets and liabilities and (ii) a reporting entity’s disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal

years. Early application is permitted. The Company adopted this new standard effective January 1, 2010 and will include the required disclosures in the Company’s Form 10-Q for the quarter ended March 31, 2010.

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

At December 31, 2009, the Company had no gross derivative assets measured at fair value on a recurring basis. At December 31, 2009, the Company had approximately $0.7 million of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy. The Company had no gross derivative assets or liabilities measured at fair value on a recurring basis at December 31, 2008.

In the fourth quarter of 2009, the Company recorded an ARO for approximately $4.5 million related to OU Spirit, which is measured at fair value on a nonrecurring basis and is considered level 3 in the fair value hierarchy. The inputs used in the valuation of the ARO include the term of the OU Spirit lease agreement, the average inflation rate, market risk premium and the credit-adjusted risk free interest rate. The term of the ARO of 35 years was determined by the OU Spirit lease agreement which states that the Company will remove the wind turbines and related facilities at the time the lease expires. The inflation rate is calculated as an average of multiple sources including the Gross Domestic Product, Consumer Price Index, etc. The market risk premium is calculated using the U.S. treasury strip rate. The credit-adjusted risk free interest rate is calculated as the market risk premium plus 120 basis points.

The three levels defined in the fair value 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 an instrument 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 following table is a summary of the fair value and carrying amount of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management (“PRM”) activities, at December 31:

	2009				2008
	Carrying		Fair		Carrying		Fair
December 31 (In millions)	Amount		Value		Amount		Value

Price Risk Management Liabilities
Energy Derivative Contracts	$	0.7	$	0.7	$	---	$	---

Long-Term Debt
Senior Notes	$	1,406.4	$	1,492.1	$	1,406.1	$	1,327.4
Industrial Authority Bonds		135.4		135.4		135.3		135.3

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 hedging and energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. The fair value of the Company’s long-term debt is based on quoted market prices.

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.

The Company recorded compensation expense of approximately $1.4 million pre-tax ($0.9 million after tax), $1.0 million pre-tax ($0.6 million after tax) and $0.9 million pre-tax ($0.6 million after tax) in 2009, 2008 and 2007, respectively, related to the Company’s portion of OGE Energy’s share-based payments. Also, during 2009, OGE Energy converted 171,670 performance units based on a payout ratio of 135.31 percent of the target number of performance units granted in February 2006, of which 39,548 performance units related to the Company’s portion. These performance units were settled in OGE Energy’s common stock.

OGE Energy issues new shares to satisfy stock option exercises and payouts of earned performance units. In 2009, 2008 and 2007, there were 324,651 shares, 875,434 shares and 496,565 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 57,439 shares, 38,684 shares and 129,568 shares, respectively, related to the Company’s employees.

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 award cycle (which, with the exception of one award of performance units to a new officer, is three years) 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 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 an award cycle (i.e., three-year cliff vesting period, other than for one award which had a two-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 an award cycle (i.e., three-year cliff vesting period, other than for one award which had a two-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. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. In 2009, 2008 and 2007, OGE Energy awarded 422,017, 242,503 and 162,730 performance units,

respectively, to certain employees of OGE Energy and its subsidiaries, of which 84,698, 43,508 and 27,322, respectively, related to the Company’s employees.

Performance Units – Total Shareholder Return

The Company recorded compensation expense of approximately $1.1 million pre-tax ($0.6 million after tax), $0.7 million pre-tax ($0.4 million after tax) and $0.6 million pre-tax ($0.4 million after tax) in 2009, 2008 and 2007, 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 award cycle (typically, three years) 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 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.

	2009			2008			2007
Expected dividend yield		4.5	%		3.8	%		3.6	%
Expected price volatility		31.0	%		18.7	%		15.9	%
Risk-free interest rate		1.25	%		2.21	%		4.47	%
Expected life of units (in years)		2.88			2.84			2.95
Fair value of units granted	$	25.55		$	33.62		$	24.18

A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on TSR at December 31, 2009 and changes during 2009 are summarized in the following table. Following the end of the 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 12/31/08		85,030	1:1
Granted (B)		61,718	1:1
Converted		(29,662)	1:1	$	0.6
Forfeited		(2,708)	1:1
Employee migration (C)		2,688	1:1
Units Outstanding at 12/31/09		117,066	1:1	$	7.7
Units Fully Vested at 12/31/09		19,686	1:1	$	1.0

(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.

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, 2009 and changes during 2009 are summarized in the following table:

			Weighted-Average
	Number		Grant Date
	of Units		Fair Value
Units Non-Vested at 12/31/08		55,368	$	30.18
Granted (A)		61,718	$	25.55
Vested		(19,686)	$	24.18
Forfeited		(2,708)	$	29.39
Employee migration (B)		2,688	$	25.57
Units Non-Vested at 12/31/09 (C)		97,380	$	28.32

(A) 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.

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

(C) Of the 97,380 performance units not vested at December 31, 2009, 80,980 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2009, there was approximately $1.1 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 1.74 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 $0.3 million pre-tax ($0.2 million after tax) in 2009, 2008 and 2007, 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 2007, 2008 and 2009 performance units was $33.59, $29.22 and $20.02, respectively.

A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on EPS at December 31, 2009 and changes during 2009 are summarized in the following table. Following the end of the performance period (typically, three years), 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 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 (D)	Value
Units Outstanding at 12/31/08		28,281	1:1
Granted (E)		20,572	1:1
Converted		(9,885)	1:1	$	0.5
Forfeited		(902)	1:1
Employee migration (F)		896	1:1
Units Outstanding at 12/31/09		38,962	1:1	$	0.6
Units Fully Vested at 12/31/09		6,507	1:1	$	0.2

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

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

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, 2009 and changes during 2009 are summarized in the following table:

			Weighted-Average
	Number		Grant Date
	of Units		Fair Value
Units Non-Vested at 12/31/08		18,396	$	30.80
Granted (A)		20,572	$	20.02
Vested		(6,507)	$	33.59
Forfeited		(902)	$	26.97
Employee migration (B)		896	$	20.01
Units Non-Vested at 12/31/09 (C)		32,455	$	23.22

(A) 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.

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

(C) Of the 32,455 performance units not vested at December 31, 2009, 26,988 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2009, there was approximately $0.3 million in unrecognized compensation cost related to non-vested performance units based on EPS which is expected to be recognized over a weighted-average period of 1.78 years.

Stock Options

The Company recorded no compensation expense in 2009, 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. A summary of the activity for OGE Energy’s stock options applicable to the Company’s employees at December 31, 2009 and changes during 2009 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 12/31/08		77,412	$	22.21
Exercised		(24,068)	$	21.38	$	0.3
Expired		(11,300)	$	28.75	$	0.3
Employee migration		(500)	$	23.58
Options Outstanding at 12/31/09		41,544	$	20.89	$	0.7		2.86	years
Options Fully Vested and Exercisable at 12/31/09		41,544	$	20.89	$	0.7		2.86	years

Restricted Stock

Under the Plans and in 2008 and 2009, 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. In 2009 and 2008, respectively, OGE Energy awarded 6,226 shares and 56,798 shares of restricted stock, of which none and 21,618 related to the Company’s employees. In 2009, there were 2,915 shares of restricted stock forfeited, of which none related to the Company’s employees.

The Company recorded compensation expense of approximately $0.4 million pre-tax ($0.2 million after tax) and $0.1 million pre-tax ($0.1 million after tax) in 2009 and 2008, respectively, 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, 2009, there was approximately $0.2 million in unrecognized compensation cost related to non-vested restricted stock which is expected to be recognized over a weighted-average period of 1.75 years.

5. Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.

Commodity Price Risk

The Company occasionally uses commodity price swap contracts to manage the Company’s commodity price risk exposures. The commodity price swap contracts involve the exchange of fixed price for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. Natural gas swaps are used to manage the Company’s natural gas price exposure associated with a wholesale generation sales contract.

On July 1, 2009, the Company, Enogex and OERI entered into hedging transactions to offset natural gas length positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the OMPA. Enogex sold physical natural gas to OERI, and the Company entered into an offsetting natural gas swap with OERI. These transactions are for approximately 50,000 MMBtu’s per month from August 2009 to December 2013.

Management may designate certain derivative instruments for the purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts. Normal purchases and normal sales contracts are not recorded in PRM 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 treatment to: (i) electric power contracts by the Company and (ii) fuel procurement by the Company.

The Company recognizes its non-exchange traded derivative instruments as PRM assets or liabilities in the Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.

Interest Rate Risk

The Company’s exposure to changes in interest rates primarily relates to short-term variable debt, treasury lock agreements and commercial paper. The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, 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.

Credit Risk

The Company is exposed to certain credit risks relating to its ongoing business operations. 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.

Cash Flow Hedges

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 or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method. 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. 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.

At December 31, 2009 and 2008, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.

Fair Value Hedges

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

At December 31, 2009 and 2008, the Company had no outstanding commodity derivative instruments or treasury lock agreements that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

For derivative instruments that are not designated as either a cash flow or fair value hedge, the gain or loss on the derivative is recognized currently in earnings.

At December 31, 2009 and 2008, the Company had no material outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.

Credit-Risk Related Contingent Features in Derivative Instruments

At December 31, 2009, the Company had no derivative instruments that contain credit-risk related contingent features.

6. 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)	2009		2008		2007
NON-CASH INVESTING AND FINANCING ACTIVITIES

OU Spirit future installment payments to developer	$	3.9	$	---	$	---
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 $8.3, $4.0, $4.0)	$	84.7	$	67.1	$	57.9
Income taxes (net of income tax refunds)		1.8		29.3		30.2

7. Income Taxes

The items comprising income tax expense are as follows:

Year ended December 31 (In millions)	2009		2008		2007
Provision (Benefit) for Current Income Taxes
Federal	$	(109.9)	$	(30.2)	$	68.3
State		(3.9)		(3.6)		0.6
Total Provision (Benefit) for Current Income Taxes		(113.8)		(33.8)		68.9
Provision for Deferred Income Taxes, net
Federal		193.1		92.1		6.9
State		3.3		(0.3)		1.5
Total Provision for Deferred Income Taxes, net		196.4		91.8		8.4
Deferred Federal Investment Tax Credits, net		(4.2)		(4.6)		(4.8)
Income Taxes Relating to Other Income and Deductions		11.6		(1.0)		0.7
Total Income Tax Expense	$	90.0	$	52.4	$	73.2

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 tax examinations by tax authorities for years prior to 2006 or state and local tax examinations by tax authorities for years prior to 2002. 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. The Company earns both Federal and Oklahoma state tax credits associated with the production from its 120 MW wind farm in northwestern Oklahoma (“Centennial”) and its 101 MW OU Spirit wind farm in western Oklahoma as well as earning Oklahoma state tax credits associated with the Company’s investment in its electric generating facilities which 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	2009			2008			2007
Statutory Federal tax rate		35.0	%		35.0	%		35.0	%
Amortization of net unfunded deferred taxes		1.0			1.3			1.3
State income taxes, net of Federal income tax benefit		0.2			(2.1)			1.2
Medicare Part D subsidy		(1.2)			(0.4)			(0.3)
Federal investment tax credits, net		(1.5)			(2.4)			(2.0)
Federal renewable energy credit (A)		(2.8)			(4.6)			(3.0)
Other		0.3			---			(1.0)
Effective income tax rate as reported		31.0	%		26.8	%		31.2	%

(A) These are credits associated with the production from the Company’s wind farms.

The Company filed a request with the Internal Revenue Service (“IRS”) on December 29, 2008 for a change in its tax method of accounting related to the capitalization of repair expenditures. The accounting method change is for income tax purposes only and would allow the Company to record a cumulative tax deduction. For financial accounting purposes, the only change is recognition of the impact of the cash flow generated by accelerating income tax deductions. On December 10, 2009, the Company received approval from the IRS for the change in accounting method. In December 2009, a claim for refund was filed to carry back the 2008 tax loss resulting in a tax refund of approximately $88.6 million, which the Company received in February 2010. The expected refund was recorded as an intercompany receivable on the Balance Sheet at December 31, 2009.

At December 31, 2009 and 2008, the Company had no material unrecognized tax benefits related to uncertain tax positions. The Company recognizes interest related to unrecognized tax benefits in interest expense and recognizes penalties in other expense.

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, 2009 and 2008, respectively, were as follows:

December 31 (In millions)	2009			2008
Current Accumulated Deferred Tax Assets
Federal tax credits	$	17.2	$		9.1
Accrued vacation		4.1			4.3
Accrued liabilities		1.0			---
Uncollectible accounts		0.7			1.1
Other		0.8			---
Total Current Accumulated Deferred Tax Assets		23.8			14.5
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	$	23.8	$		12.7
Non-Current Accumulated Deferred Tax Liabilities
Accelerated depreciation and other property related differences	$	961.3	$		734.2
Company pension plan		80.7			77.6
Income taxes refundable to customers, net		7.4			5.7
Bond redemption-unamortized costs		5.2			5.7
Regulatory asset		0.2			3.2
Total Non-Current Accumulated Deferred Tax Liabilities		1,054.8			826.4
Non-Current Accumulated Deferred Tax Assets
Regulatory liabilities		(51.1)			(58.5)
Postretirement medical and life insurance benefits		(35.0)			(23.5)
State tax credits		(28.5)			(11.8)
Deferred Federal investment tax credits		(5.1)			(6.7)
Derivative instruments		(0.3)			---
Other		(3.6)			(3.1)
Total Non-Current Accumulated Deferred Tax Assets		(123.6)			(103.6)
Non-Current Accumulated Deferred Income Tax Liabilities, net	$	931.2	$		722.8

The Company currently estimates a Federal tax net operating loss for 2009 primarily caused by the accelerated tax depreciation provisions contained within the American Recovery and Reinvestment Act of 2009 (“ARRA”). ARRA allows a current deduction for 50 percent of the cost of certain property placed into service during 2009. This tax loss results in an approximate $39 million current income tax receivable related to the 2009 tax year. On November 6, 2009, the Worker, Homeownership, and Business Assistance Act of 2009 was signed into law by the President. This new law provides for a five-year carry back of net operating losses incurred in 2008 or 2009. This expanded carryback period will enable the Company to carry back the entire 2009 tax loss and obtain a tax refund of approximately $39 million, which the Company expects to receive during 2010.

The Company had a Federal renewable energy tax credit carryover from 2008 of approximately $9.1 million with an additional $8.1 million in credits being generated during 2009. In addition, the Company has an Oklahoma tax credit carryover from 2008 of approximately $18.2 million. During 2009, additional Oklahoma tax credits of approximately $28.2 million were generated or purchased by the Company. The Company currently believes that approximately $4.4 million of these state tax credit amounts will be utilized in the 2009 tax year with approximately $42.0 million being carried over to 2010 and later tax years. These Federal and state tax credits will begin to expire in 2019; however, the Company expects that all Federal and state tax credits will be fully utilized prior to expiration.

8. Common Stock and Cumulative Preferred Stock

There were no new shares of common stock issued in 2009, 2008 or 2007. The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.

9. Long-Term Debt

A summary of the Company’s long-term debt is included in the Statements of Capitalization. At December 31, 2009, the Company was in compliance with all of its debt agreements.

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
0.30% - 1.00% Garfield Industrial Authority, January 1, 2025		$	47.0
0.42% - 0.74% Muskogee Industrial Authority, January 1, 2025			32.4
0.42% - 0.75% Muskogee Industrial Authority, June 1, 2027			56.0
Total (redeemable during next 12 months)		$	135.4

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

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 and the 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.

10. Short-Term Debt

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper, by borrowings under its revolving credit agreement or by advances from OGE Energy. There was no short-term debt outstanding at December 31, 2009 or 2008. Also, at December 31, 2009, the Company had no outstanding advances from OGE Energy. At December 31, 2008, the Company had approximately $17.6 million in outstanding advances from OGE Energy. The following table provides information regarding OGE Energy’s and the Company’s revolving credit agreements and available cash at December 31, 2009.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate	Maturity
OGE Energy (B)	$	596.0	$	175.0	0.27% (D)	December 6, 2012
The Company (C)		389.0		10.2	0.14% (D)	December 6, 2012
		985.0		185.2	0.26%
Cash		---		N/A	N/A	N/A
Total	$	985.0	$	185.2	0.26%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2009.

(B) 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, 2009, there were no outstanding borrowings under this revolving credit agreement and approximately $175.0 million in outstanding commercial paper borrowings.

(C) 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, 2009, there was approximately $10.2 million supporting letters of credit. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2009.

(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements and commercial paper borrowings.

OGE Energy’s and the Company’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. 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.

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.

11. Retirement Plans and Postretirement Benefit Plans

In December 2008, the FASB issued “Employer’s Disclosures about Postretirement Benefit Plan Assets,” which amends previously issued accounting guidance in this area. The new standard requires additional disclosures related to: (i) investment policies and strategies, (ii) categories of plan assets, (iii) fair value measurement of plan assets and (iv) significant concentrations of risk. The Company adopted this new standard effective December 31, 2009 and has presented the additional disclosures below.

Defined Benefit Pension Plan

In October 2009, OGE Energy’s qualified defined benefit retirement plan (“Pension Plan”) and OGE Energy’s qualified defined contribution retirement plan (“401(k) Plan”) were amended, effective December 31, 2009, to offer a one-time irrevocable election (the “Choice Program”) for eligible employees, depending on their hire date, to select a future retirement benefit combination from OGE Energy’s Pension Plan and OGE Energy’s 401(k) Plan. Eligible employees hired before February 1, 2000, were allowed to select one of three options as the future retirement benefit combination and eligible employees hired on or after February 1, 2000, and before December 1, 2009, were allowed to select from two options as the future retirement benefit combination as discussed below.

Eligible employees hired before February 1, 2000, were allowed to select one of following three options as the future retirement benefit combination:

Option 1: Stay or participate in the current Pension Plan where employees will receive the greater of the cash balance benefit discussed below under Option 1 for employees hired after February 1, 2000 or a benefit based primarily on years of credited service and the average of the five highest consecutive years of compensation during an employee’s last 10 years prior to retirement, with reductions in benefits for each year prior to age 62 unless the employee’s age and years of credited service equal or exceed 80. Social Security benefits are deducted in determining benefits payable under the Pension Plan. Also, as part of Option 1, employees will stay in their current 401(k) Plan matching contribution formula where, for each pay period beginning on or after January 1, 2010, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 50 percent of the participant’s contributions up to six percent of compensation for participants who have less than 20 years of service (as defined in the 401(k) Plan) and 75 percent of the participant’s contributions up to six percent of compensation for participants who have 20 or more years of service.

Option 2: Freeze the current monthly income benefit under the Pension Plan at December 31, 2009, and, for each pay period beginning on or after January 1, 2010, OGE Energy will also contribute to the 401(k) Plan, on behalf of each participant, 200 percent of the participant’s contributions up to five percent of compensation.

Option 3: Freeze and convert the current Pension Plan benefit at December 31, 2009, which will be based on the lump-sum value of the participant’s benefit at December 31, 2009, determined as if the participant had terminated employment and commenced benefit payments on that date, to a stable value account balance which will only accrue annual interest credits in the future, and, for each pay period beginning on or after January 1, 2010, OGE Energy will also contribute to the 401(k) Plan, on behalf of each participant, 100 percent of the contributions up to six percent of compensation.

Eligible employees hired on or after February 1, 2000, and before December 1, 2009, were allowed to select from the following two options as the future retirement benefit combination:

Option 1: Stay or participate in the current Pension Plan’s cash balance benefit, 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, as well as stay in their current 401(k) Plan matching contribution formula where, for each pay period beginning on or after January 1, 2010, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 100 percent of the participant’s contributions up to six percent of compensation.

Option 2: Elect not to participate in or, for those currently participating, freeze the current cash balance benefit under the Pension Plan at December 31, 2009 so that it will only accrue annual interest credits in the future, and, for each pay period beginning on or after January 1, 2010, OGE Energy will also contribute to the 401(k) Plan, on behalf of each participant, 200 percent of the participant’s contributions up to five percent of compensation.

Employees hired or rehired on or after December 1, 2009, will only be eligible to participate in the 401(k) Plan where, for each pay period, OGE Energy will contribute to the 401(k) Plan, on behalf of each participant, 200 percent of the participant’s contributions up to five percent of compensation.

It is OGE Energy’s policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by OGE Energy’s actuarial consultants. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future. During each of 2009 and 2008, OGE Energy made contributions to its Pension Plan of approximately $50.0 million, of which approximately $47.0 million in each of 2009 and 2008 was 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 2010, 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 2010 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.

OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. The pension settlement charge and retirement restoration plan settlement charge did not require a cash outlay by OGE Energy and did not increase OGE Energy’s total pension expense or retirement restoration expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions)	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 and Arkansas jurisdictional portion of these charges were recorded as a regulatory asset (see Note 1 for a further discussion).

Pension Plan Costs and Assumptions

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. 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. In accordance with the Pension Protection Act, OGE Energy implemented the following changes to its Pension Plan and its 401(k) Plan, as applicable: (i) effective January 1, 2007, OGE Energy’s Pension Plan and 401(k) Plan were amended to incorporate clarifying provisions and changes relating to the Pension Protection Act notice requirements, (ii) effective January 1, 2007, OGE Energy Pension Plan and 401(k) Plan were amended to allow a non-spouse beneficiary to directly rollover an eligible distribution to an eligible individual retirement account, (iii) effective January 1, 2008, OGE Energy’s 401(k) Plan was amended to provide 100 percent vesting after completing three years of service, (iv) for OGE Energy’s 401(k) Plan, effective January 18, 2008, that plan was amended to implement an eligible automatic contribution arrangement and provide for a qualified default investment alternative consistent with the U.S. Department of Labor regulations, (v) effective January 1, 2008, terminated vested benefits, as defined in the Pension Plan, are payable to participants who, on or after January 1, 2008, leave the Company prior to retirement with at least three years of vesting service. Participants terminating before completing three years of vesting service and attaining age 65 will not receive a benefit, (vi) effective January 1, 2008, OGE Energy’s Pension Plan was amended to incorporate funding-based limitations which restrict, among other things, benefit accruals and the forms in which benefits may be paid if the Pension Plan’s funding level falls below certain levels set by the Pension Protection Act and (vii) effective January 18, 2008, OGE Energy’s 401(k) Plan was amended so that a participant may elect, in accordance with the 401(k) Plan procedures, to have his or her salary deferral rate to be made in the future automatically increased annually on a date and in an amount as specified by the participant in such election. 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 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 Investment Committee (the “Investment Committee”).

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

Asset Class	Target Allocation			Minimum			Maximum
Domestic All-Cap Equity		20	%		---	%		25	%
Domestic Equity Passive		10	%		---	%		60	%
Domestic Mid-Cap Equity		10	%		---	%		10	%
Domestic Small-Cap Equity		10	%		---	%		10	%
International Equity		15	%		---	%		15	%
Fixed Income Domestic		35	%		30	%		70	%

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	Barclays Capital 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 (“Fitch”). The portfolio may invest up to 10 percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of 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-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International Europe, Australia and the Far East Index (“EAFE”) is the benchmark for comparative performance purposes. The EAFE Index is a market value weighted index comprised of over 1,000 companies traded on the stock markets of Europe, Australia, New Zealand and the Far East. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) after accounting for price appreciation. A minimum of 95 percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Options or financial futures may not be purchased unless prior approval of the Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of 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.

Plan Assets

The following table is a summary of OGE Energy’s Pension Plan’s assets that are measured at fair value on a recurring basis at December 31, 2009, of which approximately $398.9 million is the Company’s portion. There were no Level 3 investments held by the Pension Plan at December 31, 2009.

(In millions)	Total		Level 1		Level 2
Common stocks
U.S. common stocks	$	152.4	$	152.4	$	---
Foreign common stocks		57.2		57.2		---
Bonds, debentures and notes (A)
Bonds, debentures and notes		119.1		---		119.1
Mortgage-backed securities		8.6		---		8.6
U.S. Government obligations
Mortgage-backed securities		72.3		---		72.3
U.S. treasury notes and bonds (B)		22.2		22.2		---
Other securities		4.5		---		4.5
Commingled fund (C)		32.8		---		32.8
Common collective trust (D)		15.9		---		15.9
Foreign government bonds		5.1		---		5.1
U.S. municipal bonds		2.5		---		2.5
Foreign mutual funds		2.0		2.0		---
Foreign preferred stock		0.9		0.9		---
U.S. mutual funds		0.8		0.8		---
Total	$	496.3	$	235.5	$	260.8

(A) This category primarily represents U.S. corporate bonds with an investment grade rating at or above Baa3 or BBB- by Moody’s, Standard & Poor’s or Fitch.

(B) This category represents U.S. treasury notes and bonds with a Moody’s rating of Aaa and Government Agency Bonds with a Moody’s rating of A1 or higher.

(C) This category represents units of participation in a commingled fund that primarily invest in stocks and bonds of U.S. companies.

(D) This category represents units of participation in an investment pool which primarily invests in commercial paper, repurchase agreements and U.S. treasury notes and bonds and certificates of deposit.

The three levels defined in the fair value hierarchy and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the Pension Plan and postretirement benefit plans have 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 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 Pension Plan’s and postretirement benefit plans 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 Pension Plan’s and postretirement benefit plans own data. The Pension Plan’s and postretirement benefit plans own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions.

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.

OGE Energy expects to pay benefits related to its Pension Plan and restoration of retirement income plan on behalf of the Company of approximately $39.9 million in 2010, $47.0 million in 2011, $59.6 million in 2012, $59.1 million in 2013, $57.2 million in 2014 and an aggregate of $221.1 million in years 2015 to 2019. These expected benefits are based on the same assumptions used to measure OGE Energy’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 10 years of vesting service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. 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 postretirement benefit costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

Plan Assets

The following table is a summary of OGE Energy’s postretirement benefit plans’ assets that are measured at fair value on a recurring basis at December 31, 2009, of which approximately $52.5 million is the Company’s portion. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2009.

(In millions)	Total		Level 1		Level 3
Group retiree medical insurance contract (A)	$	49.3	$	---	$	49.3
U.S. mutual fund (B)		4.9		4.9		---
Cash		0.8		0.8		---
Total	$	55.0	$	5.7	$	49.3

(A) This category represents a group retiree medical insurance contract which invests in a pool of mutual funds, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.

(B) This category represents investments in a U.S. equity mutual fund.

The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract.

The following table is a summary of OGE Energy’s postretirement benefit plans’ assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

	Group retiree medical insurance contract
Year Ended December 31 (In millions)	2009
Balance at January 1	$	55.1
Actual return on plan assets relating to assets held at the reporting date		(5.8)
Purchases, sales, issuances and settlements, net		---
Transfers in and/or out of Level 3		---
Balance at December 31	$	49.3

At December 31, 2009, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $232.5 million and $52.5 million, respectively, for an underfunded status of approximately $180.0 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, 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.

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 9.49 percent in 2010 with the rates trending downward to five percent by 2018. 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)	2009		2008		2007
Effect on aggregate of the service and interest cost components	$	1.8	$	1.7	$	1.8
Effect on accumulated postretirement benefit obligations		31.2		22.3		21.4

ONE-PERCENTAGE POINT DECREASE
Year ended December 31 (In millions)	2009		2008		2007
Effect on aggregate of the service and interest cost components	$	1.4	$	1.4	$	1.5
Effect on accumulated postretirement benefit obligations		25.6		18.6		17.8

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 postretirement benefit obligation (“APBO”) for OGE Energy with respect to its postretirement medical plan will be reduced by approximately $50.3 million as a result of savings to OGE Energy resulting from the Medicare Act provided subsidy, which will reduce OGE Energy’s costs for its postretirement medical plan by approximately $6.8 million annually. The $6.8 million in annual savings is comprised of a reduction of approximately $3.2 million from amortization of the $50.3 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $3.1 million and a reduction in the service cost due to the subsidy of approximately $0.5 million.

The Company expects to pay gross benefits payments related to its postretirement benefit plans, including prescription drug benefits, of approximately $11.3 million in 2010, $12.4 million in 2011, $13.4 million in 2012, $14.6 million in 2013, $15.7 million in 2014 and an aggregate of $91.7 million in years 2015 to 2019. Based on the current law, the Company expects to receive Federal subsidy receipts provided by the Medicare Act of approximately $1.5 million in 2010, $1.7 million in 2011, $1.9 million in 2012, $2.1 million in 2013, $2.3 million in 2014 and an aggregate of $14.4 million in years 2015 to 2019. OGE Energy received approximately $1.5 million in Federal subsidy receipts in 2009.

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 2009 and 2008. 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 postretirement benefit obligation. The accumulated postretirement benefit obligation for OGE Energy’s Pension Plan and restoration of retirement income plan 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, 2009 was approximately $445.0 million and $1.6 million, respectively. 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 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)	2009		2008		2009		2008		2009		2008

Change in Benefit Obligation
Beginning obligations	$	(432.6)	$	(413.6)	$	(1.1)	$	(0.8)	$	(191.9)	$	(179.2)
Service cost		(11.5)		(12.4)		---		---		(2.2)		(2.3)
Interest cost		(24.7)		(24.9)		(0.1)		(0.1)		(11.5)		(11.1)
Plan amendments		(9.7)		---		(0.5)		---		---		---
Plan curtailments		0.2		---		---		---		---		---
Participants’ contributions		---		---		---		---		(5.6)		(4.9)
Actuarial gains (losses)		(27.7)		(15.3)		(0.1)		(0.5)		(35.1)		(6.4)
Benefits paid		29.6		33.6		---		0.3		13.8		12.0
Ending obligations		(476.4)		(432.6)		(1.8)		(1.1)		(232.5)		(191.9)

Change in Plans’ Assets
Beginning fair value		309.2		400.7		---		---		55.1		76.0
Actual return on plans’ assets		72.3		(104.9)		---		---		(7.1)		(18.7)
Employer contributions		47.0		47.0		---		0.3		12.6		4.9
Participants’ contributions		---		---		---		---		5.7		4.9
Benefits paid		(29.6)		(33.6)		---		(0.3)		(13.8)		(12.0)
Ending fair value		398.9		309.2		---		---		52.5		55.1
Funded status at end of year	$	(77.5)	$	(123.4)	$	(1.8)	$	(1.1)	$	(180.0)	$	(136.8)

Net Periodic Benefit Cost

								Restoration of Retirement						Postretirement
		Pension Plan						Income Plan						Benefit Plans
Year ended December 31
(In millions)		2009		2008		2007		2009		2008		2007		2009		2008		2007
Service cost		$	11.5	$	12.4	$	13.8	$	---	$	---	$	---	$	2.2	$	2.3	$	2.7
Interest cost			24.7		24.9		25.6		0.1		0.1		---		11.5		11.1		10.4
Return on plan assets			(26.3)		(34.3)		(34.5)		---		---		---		(6.3)		(6.3)		(5.7)
Amortization of transition
obligation			---		---		---		---		---		---		2.5		2.5		2.5
Amortization of net loss			18.5		7.4		8.4		0.1		0.1		---		4.1		3.5		5.5
Amortization of unrecognized
prior service cost			0.9		1.1		4.5		0.1		0.1		0.1		0.7		1.5		1.5
Curtailments			0.2		---		---		---		---		---		---		---		---
Settlement			---		---		13.3		---		---		0.1		---		---		---
Net periodic benefit cost (A)		$	29.5	$	11.5	$	31.1	$	0.3	$	0.3	$	0.2	$	14.7	$	14.6	$	16.9
(A) In addition to the approximately $29.8 million, $11.8 million and $31.3 million of net periodic benefit cost recognized in 2009, 2008 and 2007, respectively, the Company recognized the following:
Ÿ	a reduction in pension expense in 2009 of approximately $1.8 million, an increase in pension expense in 2008 of approximately $7.5 million and a reduction in pension expense in 2007 of approximately $8.3 million to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1); and
Ÿ	a reduction in pension expense in 2009 of approximately $3.2 million in the Arkansas jurisdiction to reflect the approval of recovery of the Company’s 2006 and 2007 pension settlement costs in the May 2009 Arkansas rate order which are identified as Deferred Pension Plan Expenses (see Note 1).

The capitalized portion of the net periodic pension benefit cost was approximately $7.5 million, $3.6 million and $5.2 million at December 31, 2009, 2008 and 2007, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $3.6 million, $4.2 million and $4.5 million at December 31, 2009, 2008 and 2007, respectively.

Rate Assumptions

	Pension Plan and			Postretirement
	Restoration of Retirement Income Plan			Benefit Plans
Year ended December 31	2009	2008	2007	2009	2008	2007
Discount rate	5.30%	6.25%	6.25%	6.00%	6.25%	6.25%
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%	N/A	N/A	N/A
Assumed health care cost trend:
Initial trend	N/A	N/A	N/A	9.49%	9.00%	9.00%
Ultimate trend rate	N/A	N/A	N/A	5.00%	4.50%	4.50%
Ultimate trend year	N/A	N/A	N/A	2018	2014	2013

N/A - not applicable

The overall expected rate of return on plan assets assumption remained at 8.50 percent in 2008 and 2009 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 $1.7 million and $1.6 million at December 31, 2009 and 2008, respectively.

Defined Contribution Retirement Plan

OGE Energy provides a 401(k) Plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as “Catch-Up Contributions,” subject to the limitations of the Code. The 401(k) Plan was amended in October 2009, as discussed previously, whereby employees were offered a one-time irrevocable election to either stay in their current 401(k) Plan where OGE Energy matching contributions are discussed below or select an option whereby, effective January 1, 2010, OGE Energy will contribute on behalf of each participant, depending on the option selected, 200 percent of the participant’s contributions up to five percent of compensation or 100 percent of the participant’s contributions up to six percent of compensation. In the current 401(k) Plan, OGE Energy contributes to the 401(k) Plan each pay period, on behalf of each participant, an amount equal to 50 percent of the participant’s contributions up to six percent of compensation for participants whose employment or re-employment date occurred before February 1, 2000 and who have less than 20 years of service, as defined in the 401(k) Plan, and an amount equal to 75 percent of the participant’s contributions up to six percent of compensation for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service, as defined in the 401(k) Plan. For participants whose employment or re-employment date occurred on or after February 1, 2000 and before December 1, 2009, under the current 401(k) Plan, OGE Energy contributes 100 percent of the participant’s contributions up to six percent of compensation. For participants hired on or after December 1, 2009, OGE Energy contributes, effective January 1, 2010, 200 percent of the participant’s contributions up to five percent of compensation. No OGE Energy contributions are made with respect to a participant’s Catch-Up Contributions,

rollover contributions, or with respect to a participant’s 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. Prior to January 1, 2010, OGE Energy’s contribution, which was initially allocated for investment to the OGE Energy Corp. Common Stock Fund, was made in shares of OGE Energy’s common stock or in cash which was used to invest in OGE Energy’s common stock. Once made, OGE Energy’s contribution could be reallocated, on any business day, by participants to other available investment options. The 401(k) Plan was amended effective January 1, 2010, whereby OGE Energy’s contribution may be directed to any available investment option in the 401(k) Plan. The Company contributed approximately $5.6 million, $5.1 million and $4.7 million in 2009, 2008 and 2007, respectively, to the 401(k) Plan.

Deferred Compensation Plan

OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded 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’ 401(k) 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 annual 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 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) 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 make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on the option the participant elected under the Choice Program discussed above, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after six years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the 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 and restoration of retirement income plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the Code.

12. Commitments and Contingencies

Operating Lease Obligations

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

											2015 and
Year ended December 31 (In millions)	2010		2011		2012		2013		2014		Beyond		Total

Operating lease obligations
Railcars	$	3.9	$	38.0	$	---	$	---	$	---	$	---	$	41.9

Payments for operating lease obligations were approximately $5.0 million, $3.9 million and $3.9 million in 2009, 2008 and 2007, respectively.

Railcar Lease Agreement

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 rates in the new agreement were higher than the rates in the Company’s previous transportation contracts.

The Company 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 Company began paying interim shipping rates, subject to refund, while this matter was pending with the STB. On July 24, 2009 the STB issued a decision awarding the Company a reduction in interim shipping rates to its Muskogee power plant. In 2009, the Company received a refund of approximately $7.7 million from Union Pacific related to payments the Company made in 2009. All refund amounts are being passed through to the Company’s customers.

The overall effect of the new BNSF Railway agreement and rail rate prescription from the STB for rail transportation to the Company’s Sooner and Muskogee power plants is expected to cause an approximate 47 percent annual increase in the Company’s delivered coal prices.

Termination of Wholesale Agreement

On May 28, 2009, the Company sent a termination notice to the Arkansas Valley Electric Cooperative (“AVEC”) that the Company would terminate its wholesale power agreement to all points of delivery where the Company sells or has sold power to AVEC, effective November 30, 2011. The Company is in the process of discussing an agreement with AVEC which could result in the Company supplying wholesale power to AVEC in the future. Any such agreement would be conditioned on the FERC and state regulatory approvals. The termination of the AVEC agreement is not expected to have a material impact to the Company’s financial position or results of operations.

Public Utility Regulatory Policy Act of 1978

At December 31, 2009, 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.

In 2009, 2008 and 2007, the Company made total payments to cogenerators of approximately $139.8 million, $152.8 million and $156.8 million, respectively, of which approximately $83.1 million, $84.4 million and $88.9 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: 2010 – $86.1 million, 2011 – $83.1 million, 2012 – $81.1 million, 2013 – $79.0 million and 2014 – $76.7 million.

Fuel Minimum Purchase Commitments

The Company purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $358.8 million, $257.6 million and $232.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. The Company has entered into future purchase commitments of necessary fuel supplies of approximately: 2010 – $340.0 million, 2011 – $63.1 million, 2012 – $21.1 million and 2013 – $1.8 million. The Company also has a coal contract for purchases from January 2011 through December 2015. As the coal purchases in this contract for years 2013 through 2015 are valued based on an index price to be determined in the future, these amounts are not disclosed.

Wind Power Purchase Commitments

The Company also received approval on January 5, 2010 from the OCC for two wind power purchase agreements with two wind developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. The Company intends to add this capability to its power-generation portfolio by the end of 2010. Under the terms of the agreements, CPV Keenan is to build a 150 MW wind farm in Woodward County and Edison Mission Energy is to build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output. See Note 13 for a further discussion.

The Company purchased wind power from FPL Energy of approximately $4.0 million, $4.4 million and $3.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. The Company has entered into future wind purchase commitments of approximately: 2010 – $10.2 million, 2011 – $51.3 million, 2012 – $52.0 million, 2013 – $52.2 million, 2014 – $52.6 million and 2015 and beyond – $730.6 million.

Long-Term Service Agreements

In July 2004, the Company acquired a 77 percent interest in the McClain Plant. As part of that acquisition, the Company became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in December 1999, and runs for the earlier of 96,000 factored-fired hours or 4,800 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2015. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used. The Company’s share of the estimated obligation under the contract, based on the projected future use of the McClain Plant, is approximately: 2010 – $1.4 million, 2011 – $15.8 million, 2012 – $1.5 million, 2013 – $1.5 million, 2014 – $17.1 million and 2015 and beyond – $1.2 million.

In September 2008, the Company acquired a 51 percent interest in the Redbud Facility. As part of that acquisition, the Company became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in January 2001, and runs for the earlier of 120,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2025. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Facility is used. The Company’s share of the estimated obligation under the contract, based on the projected future use of the Redbud Facility, is approximately: 2010 – $2.3 million, 2011 – $0.6 million, 2012 – $10.5 million, 2013 – $11.9 million, 2014 – $7.4 million and 2015 and beyond – $70.1 million.

Natural Gas Units

In August 2009, the Company issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2009 through March 2010. The gas supply purchases from January through March 2010 account for approximately 18 percent of the Company’s projected 2010 natural gas requirements. The RFP process was completed on September 10, 2009. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2010. Additional gas supplies to fulfill the Company’s remaining 2010 natural gas requirements will be acquired through additional RFPs in early to mid-2010, along with monthly and daily purchases, all of which are expected to be made at market prices.

Coal

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 was a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleged: (a) each of the named defendants had improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts were improper; (c) transactions by affiliated companies were not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg sought the following damages: (a) additional royalties which he claimed 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. Various appeals and hearings were held in this matter from 2006 to late 2009. In October 2009, this matter concluded with the dismissal of all complaints against the Company. The Company now considers this case closed.

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 other 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. On March 10, 2009, the Oklahoma Attorney General, the Company, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed. On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the OCC order which authorizes the Company to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether the Company’s collection and remittance of such sales tax should be discontinued prospectively. On December 21, 2009, the plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny the Company’s writ of prohibition and to remand the cause to the District Court. On December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to dismiss the cause and close the cause at the OCC. If the OCC Staff’s motion is granted, the plaintiffs would be required to file a new cause in order to ask for prospective relief. In its motion, the OCC Staff stated that the plaintiff’s counsel advised the OCC Staff counsel that the plaintiffs have no desire to seek a determination regarding prospective relief from the OCC. It is unknown whether the plaintiffs will attempt to continue the District Court action. The Company believes that the lawsuit 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 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 arbitration hearing was completed recently and the next step is briefing by the parties. 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

The activities of the Company are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including 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 can impose burdensome 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 (“Federal 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.

Air

Sulfur Dioxide

The 1990 Federal 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 U.S. Environmental Protection Agency (“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 2009, 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 10,000 banked allowances in 2009 for approximately $0.8 million. Also, during 2009, the Company received proceeds of approximately $0.1 million from the annual EPA spot (year 2009) and seven-year advance (year 2016) allowance auctions that were held in March 2009.

Nitrogen Oxides

On January 25, 2010, the EPA released a rule strengthening the National Ambient Air Quality Standards (“NAAQS”) for oxides of nitrogen as measured by nitrogen dioxide (“NO2”) which is effective March 26, 2011. The rule establishes a new one-hour standard and monitoring requirements, as well as an approach for implementing the new standard. Oklahoma is currently in attainment with the new standard and it is anticipated that Oklahoma will be designated “unclassifiable” in 2012 because the new monitoring requirements will not yet be fully implemented. After the new monitoring network is deployed and has collected three years of air quality data, the EPA will re-designate areas in 2016 or 2017 based on the new data. It is currently anticipated that Oklahoma will be designated “attainment” at that time.

With respect to the nitrogen oxide (“NOX”) regulations of the acid rain program, the Company committed to meeting a 0.45 lbs/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 2009 were approximately 0.319 lbs/MMBtu.

Particulate Matter

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.

Ozone

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 had 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 was expected to determine a final designation by March 2010. States were to 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 were the most likely areas to be designated non-attainment in Oklahoma. On September 16, 2009, the EPA announced that they would reconsider the 2008 national primary and secondary ozone standards to ensure they are scientifically sound and protective of human health. The EPA also proposed to keep the 2008 standards unchanged for the purpose of attainment and non-attainment area designations. On January 19, 2010, the EPA published a decision to extend by

one year the deadline for promulgating initial area designations for the NAAQS that were promulgated in March 2008. The new deadline is March 12, 2011.

Greenhouse Gases

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 and regulation at the Federal level, actions at the state level, litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. Recently, two Federal courts of appeal have reinstated nuisance-type claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. Although the Company is not a defendant in either proceeding, additional litigation in Federal and state courts over these issues is expected.

Interstate Transport

On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Federal 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 Oklahoma to the EPA on December 5, 2007. On June 5, 2009, a lawsuit was filed by WildEarth Guardians, a third-party, in an attempt to force the EPA to act because the EPA had not yet approved transport state implementation plans from California, Colorado, Idaho, New Mexico, North Dakota, Oklahoma and Oregon. A consent decree was proposed December 7, 2009 and the comment period closed January 5, 2010. The outcome of this matter is uncertain at this time.

EPA 2008 Information Request

In July 2008, the Company received a request for information from the EPA regarding Federal 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 Federal Clean Air Act’s new source review process. The Company believes it has acted in full compliance with the Federal 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.

Title V Permits and Emission Fees

At December 31, 2009, the Company had received Title V permits for all of its generating stations and intends to continue to renew these permits as necessary. Air permit fees for the Company’s generating stations were approximately $0.9 million in 2009.

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 2009, the Company obtained refunds of approximately $2.4 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 filed an Oklahoma Pollutant Discharge Elimination (“OPDES”) permit renewal application with the state of Oklahoma on August 4, 2008 for its Seminole generating station and received a draft permit for review on January 9, 2009 and December 4, 2009. The Company provided comments on the initial draft permit and will provide additional comments on the final draft permit during the public comment period. In addition, the Company filed OPDES permit renewal applications for its Muskogee, Mustang and Horseshoe Lake generating stations on March 4, 2009, April 3, 2009 and October 29, 2009, respectively.

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 13 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.

13. Rate Matters and Regulation

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, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy (“DOE”) has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2009, approximately 89 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and three percent to the FERC.

Completed Regulatory Matters

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 in 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. On March 18, 2009, the Company, the APSC Staff and the Arkansas Attorney General filed a settlement agreement in this matter calling for a general rate increase of approximately $13.6 million. This settlement agreement also allows implementation of the Company’s “time-of-use” tariff which allows participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. On May 20, 2009, the APSC approved a general rate increase of approximately $13.3 million, which excludes approximately $0.3 million in storm costs discussed below. The Company implemented the new electric rates effective June 1, 2009.

2008 Arkansas 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 requested 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. As discussed above, on March 18, 2009, the Company, the APSC Staff and the Arkansas Attorney General reached a settlement agreement in the Company’s Arkansas rate case which included recovery of these storm costs. As discussed above, in its May 20, 2009 order approving the settlement agreement, the APSC directed the Company to file an exact recovery rider for its 2008 storm costs. The Company filed this recovery rider and the rider was implemented June 1, 2009.

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 to determine 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 its proposed system hardening plan with a recovery rider. On March 20, 2009, all parties to this case signed a settlement agreement recommending a three-year plan that includes up to $35.3 million in capital expenditures and approximately $33.2 million in operating expenses for aggressive vegetation management and a recovery rider. On May 13, 2009, the OCC issued an order approving the settlement agreement in this matter. The new rider, which will allow the Company to recover costs related to system hardening incurred on or after June 15, 2009, was implemented July 1, 2009.

Security Enhancements

On January 15, 2009, the Company filed an application with the OCC to amend its security plan. The Company sought approval of new security projects and cost recovery through the previously authorized security rider. The annual revenue requirement is approximately $0.9 million. On May 29, 2009, the OCC issued an order approving a settlement agreement in this matter that incorporated the Company’s requested rate relief. The new rider was implemented June 1, 2009.

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. 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 increase of approximately $2.4 million, subject to refund. On June 25, 2009, the FERC issued an order approving an approximate $1.3 million increase in revenues from the Company’s transmission customers compared to the approximate $2.4 million increase in revenues previously implemented in July 2008. In accordance with the FERC formula, overcollections for the prior period are to be credited to transmission customers as part of the calculation of the rates to be paid in 2010.

2009 Oklahoma Rate Case Filing

On February 27, 2009, the Company filed its rate case with the OCC requesting a rate increase of approximately $110 million. On July 24, 2009, the OCC issued an order authorizing: (i) an annual net increase of approximately $48.3 million in the Company’s rates to its Oklahoma retail customers, which includes an increase in the residential customer charge from $6.50/month to $13.00/month, (ii) creation of a new recovery rider to permit the recovery of up to $20 million of capital expenditures and operation and maintenance expenses associated with the Company’s smart grid project in Norman, Oklahoma, which was implemented in February 2010, (iii) continued utilization of a return on equity (“ROE”) of 10.75 percent under various recovery riders previously approved by the OCC and (iv) recovery through the Company’s fuel adjustment clause of approximately $4.8 million annually of certain expenses that historically had been recovered through base rates. New electric rates were implemented August 3, 2009. The Company expects the impact of the rate increase on its customers and service territory to be minimal over the next 12 months as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries and from lower than forecasted fuel costs in 2010.

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. On August 12, 2009, all parties to this case signed a settlement agreement in this matter, stating that the Company’s generation and fuel procurement processes and costs during the 2007 calendar year were prudent. A hearing on the settlement agreement was held on September 10, 2009 and the administrative law judge recommended approval of the settlement agreement. On October 15, 2009, the OCC issued an order adopting the findings in the settlement agreement.

OU Spirit 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 OU Spirit. As discussed below, OU Spirit is part of the Company’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, the Company filed an application with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct OU Spirit at a cost of approximately $265.8 million. On October 15, 2009, all parties to this case signed a settlement agreement that would provide pre-approval of OU Spirit and authorize the Company to begin recovering the costs of OU Spirit through a rider mechanism as the 44 turbines were placed into service in November and December 2009 and began delivering electricity to the Company’s customers. The rider will be in effect until OU Spirit is added to the Company’s regulated rate base as part of the Company’s next general rate case, which is expected to be based on a 2010 test year and completed in 2011, at which time the rider will cease. The settlement agreement also assigns to the Company’s customers the proceeds from the sale of OU Spirit renewable energy credits to the University of Oklahoma. The settlement agreement permits the recovery of up to $270 million of eligible construction costs, including recovery of the costs of the conservation project for the lesser prairie chicken as discussed below. The net impact on the average residential customer’s 2010 electric bill is estimated to be approximately 90 cents per month, decreasing to 80 cents per month in 2011. On November 25, 2009, the Company received an order from the OCC approving the settlement agreement in this case, with the rider being implemented on December 4, 2009. Capital expenditures associated with this project were approximately $270 million.

Renewable Energy Filing

output. On October 30, 2009, the Company filed separate applications with the OCC seeking pre-approval for the recovery of the costs associated with purchasing power from these projects. On December 9, 2009, all parties to these cases signed settlement agreements whereby the stipulating parties requested that the OCC issue orders: (i) finding that the execution of the power purchase agreements complied with the OCC competitive bidding rules, are prudent and are in the public’s interest, (ii) approving the power purchase agreements and (iii) authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. On January 5, 2010, the Company received an order from the OCC approving the power purchase agreements and authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. The two wind farms are expected to be in service by the end of 2010. Negotiations with the third bidder on the Company’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.

Windspeed Transmission Line Project

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 (“Windspeed”) at a construction cost of approximately $211 million, plus approximately $7 million in AFUDC, for a total of approximately $218 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 April 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to the Company’s Oklahoma customers. 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 the Windspeed transmission line 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 an expected 2011 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. At December 31, 2009, the construction costs and AFUDC incurred were approximately $184.9 million. 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 District EHV substation. In 2009, the Company received a favorable outcome in five local court cases challenging the Company’s use of eminent domain to obtain rights-of-way. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

Market-Based Rate Authority

On December 22, 2003, the Company and OERI filed a triennial market power update with the FERC 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 two new interim tests, a pivotal supplier screen test and a market share screen test. On February 7, 2005, the Company and OERI submitted a compliance filing to the FERC that applied the interim tests to the Company and OERI. On June 7, 2005, the FERC issued an order finding that the Company and OERI had failed the market share screen test meant to determine whether entities with market-based rate authority have market power in wholesale power markets. Based on the failed market share screen test, the FERC established a rebuttable presumption that the Company and OERI have the ability to exercise market power in the Company’s control area. On August 8, 2005, the Company and OERI informed the FERC that they would: (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 would be filed with the FERC and that the Company and OERI would not make such sales under their respective market-based rate tariffs. 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 and OERI 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). As part of the market-based rate matter, the Company and OERI have filed a series of tariff revisions

to comply with the FERC orders and such revisions have been accepted by the FERC. Also, as part of the mitigation for the failed market share screen test discussed above, on an ongoing basis, the Company and OERI file change of status reports and triennial market power reports according to the FERC orders and regulations. In July 2009, the Company and OERI filed a triennial market power update with the FERC which reported that there have been no significant changes to the Company’s and OERI’s market-based rate authority.

Conservation and Energy Efficiency Programs

In June and September 2009, the Company filed applications with the APSC and the OCC seeking approval of a comprehensive Demand Program portfolio designed to build on the success of its earlier programs and further promote energy efficiency and conservation for each class of Company customers. Several programs are proposed in these applications, ranging from residential weatherization to commercial lighting. In seeking approval of these new programs, the Company also seeks recovery of the program and related costs through a rider that would be added to customers’ electric bills. In Arkansas, the Company’s program is expected to cost approximately $2 million over an 18-month period and is expected to increase the average residential electric bill by less than $1.00 per month. In Oklahoma, the Company’s program is expected to cost approximately $45 million over three years and is expected to increase the average residential electric bill by less than $1.00 per month in 2010 and by approximately $1.40 per month in 2011 and 2012 depending on the success of the programs. In addition to program cost recovery, the OCC also granted the Company recovery of: (i) lost revenues resulting from the reduced Kilowatt-hour sales between rate cases and (ii) performance-based incentives of 15 percent of the net savings associated with the programs. A hearing in the APSC matter was held on October 29, 2009 and the Company received an order in this matter on February 3, 2010. A settlement agreement was signed in the OCC matter by several parties to this case on January 15, 2010 with a hearing being held on January 21, 2010, where the parties who had not previously signed the settlement agreement indicated that they did not oppose the settlement agreement. The Company received an order in the OCC matter on February 10, 2010.

Pending Regulatory Matters

SPP Transmission/Substation Projects

The SPP is a regional transmission organization (“RTO”) under the jurisdiction of the FERC, which was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP’s tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed has the first obligation to build.

There are several studies currently under review at the SPP including the Extra High Voltage (“EHV”) study that focuses on year 2026 and beyond to address issues of regional and interregional importance. The EHV study suggests overlaying the SPP footprint with a 345 kilovolt (“kV”), 500kV and 765kV transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP’s regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP’s future needs. The Company expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP’s plans.

to the base-plan funding mechanism as provided in the SPP tariff for application to such improvements. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

On April 28, 2009, the SPP approved a set of 345 kV projects referred to as “Balanced Portfolio 3E”. Balanced Portfolio 3E includes four projects to be built by the Company and includes: (i) construction of approximately 120 miles of transmission line from the Company’s Seminole substation in a northeastern direction to the Company’s Muskogee substation at a cost of approximately $131 million for the Company, which is expected to be in service by December 2014, (ii) construction of approximately 72 miles of transmission line from the Company’s Woodward District EHV substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at a cost of approximately $120 million for the Company, which is expected to be in service by April 2014, (iii) construction of approximately 38 miles of transmission line from the Company’s Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of approximately $41 million for the Company, which is expected to be in service by December 2012 and (iv) construction of a new substation near Anadarko which is expected to consist of a 345/138 kV transformer and substation breakers and will be built in the Company’s portion of the Cimarron-Lawton East Side 345 kV line at an estimated cost of approximately $8 million for the Company, which is expected to be in service by December 2012. On June 19, 2009, the Company received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, the Company responded to the SPP that the Company will construct the Balanced Portfolio 3E projects discussed above beginning in early 2010. The capital expenditures related to the Balanced Portfolio 3E projects are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

Smart Grid Application

In February 2009, the President signed into law the ARRA. Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy. After review of the ARRA, the Company filed a grant request on August 4, 2009 for $130 million with the DOE to be used for the Smart Grid application in the Company’s service territory. On October 27, 2009, the Company received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million. Receipt of the grant monies is contingent upon successful negotiations with the DOE on final details of the award. The Company expects to file an application with the OCC for requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant during the first quarter of 2010. Separately, on November 30, 2009, the Company requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for the Company’s workforce. Recipients of the grant are expected to be announced in the first quarter of 2010.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2008

On July 20, 2009, the OCC Staff filed an application for a public hearing to review and monitor the Company’s application of the 2008 fuel adjustment clause. On September 18, 2009, the Company responded by filing the necessary information and documents to satisfy the OCC’s minimum filing requirement rules. On February 2, 2010, a procedural schedule was established in this matter with a hearing scheduled for May 26, 2010.

North American Electric Reliability Corporation

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 Corporation (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. In September 2009, the Company completed a NERC Critical Infrastructure Protection (“CIP”) spot check audit. Resolution of any audit findings is expected in 2010; 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 compliance audit every three years as well as periodic spot check audits. The next compliance audit is scheduled for 2011, which will incorporate both NERC CIP and non-CIP standards.

Summary

The Energy Policy Act of 2005, the actions of the FERC 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.

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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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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 17, 2010 expressed an unqualified opinion thereon.

	/s/ Ernst & Young LLP
	Ernst & Young LLP

Oklahoma City, Oklahoma

February 17, 2010

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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	2009	$	336.7	$	425.3		$	577.9	$	411.3	$	1,751.2
	2008		386.4		520.7			682.5		369.9		1,959.5

Operating income (loss)	2009	$	18.8	$	96.5		$	193.2	$	45.6	$	354.1
	2008		(0.7)		70.7			169.6		38.7		278.3

Net income (loss)	2009	$	1.3	$	56.4		$	123.2	$	19.5	$	200.4
	2008		(11.3)		30.9			107.1		16.3		143.0

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).

102

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, 2009. 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, 2009, 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/ Sean Trauschke		/s/ Scott Forbes
Sean Trauschke, Vice President		Scott Forbes, Controller
and Chief Financial Officer		and Chief Accounting Officer

103

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, 2009, 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, 2009, based on the 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, 2009 and 2008, 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, 2009 of Oklahoma Gas and Electric Company and our report dated February 17, 2010 expressed an unqualified opinion thereon.

	/s/ Ernst & Young LLP
	Ernst & Young LLP

Oklahoma City, Oklahoma

February 17, 2010

104

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 “Investor Relations”, “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 information regarding 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 2009 were $2,054,200 for OGE Energy’s 2009 financial statement audit. These fees include $1,530,000 for the integrated audit of OGE Energy’s annual financial statements and its internal control over financial reporting and $125,000 for services in support of debt and stock offerings. 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.

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 2009, this amount includes estimated billings for the completion of the 2009 audit, which were rendered after year-end.

105

Audit-Related Fees

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2009 were $123,100, of which $104,000 was for employee benefit plan audits and $19,100 for other audit-related services.

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.

Tax Fees

The aggregate fees billed for tax services for the fiscal year ended December 31, 2009 were $495,145. These fees include $481,490 for tax preparation and compliance ($75,500 for the review of Federal and state tax returns and $405,990 for assistance with examinations and other return issues) and $13,655 for other tax services.

The aggregate fees billed for tax services for the fiscal year ended December 31, 2008 were $374,100. These fees include $186,520 for tax preparation and compliance ($70,500 for the review of Federal and state tax returns and $116,020 for assistance with examinations and other return issues) and $187,580 for other tax services.

All Other Fees

There were no other fees billed by the independent auditors to OGE Energy in 2009 and 2008 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, the Company 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 2009, 100 percent of the audit fees, 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:

Ÿ	Statements of Income for the years ended December 31, 2009, 2008 and 2007

Ÿ	Balance Sheets at December 31, 2009 and 2008

Ÿ	Statements of Capitalization at December 31, 2009 and 2008

Ÿ	Statements of Changes in Stockholder’s Equity for the years ended December 31, 2009, 2008 and 2007

106

Ÿ	Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007

Ÿ	Notes to Financial Statements

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

Ÿ	Management’s Report on Internal Control Over Financial Reporting

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

Supplementary Data

Ÿ	Interim Financial Information

2. Financial Statement Schedule (included in Part IV)		Page

Schedule II - Valuation and Qualifying Accounts		113

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)
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)

107

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 OGE Energy 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)
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

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		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)
4.10		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)
4.11		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 8-K filed July 6, 2009 (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. (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)

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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 10.02 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2009 (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		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)
10.16		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)
10.17*		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)
10.18*		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)
10.19*		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)
10.20*		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)
10.21*		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

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		reference herein)
10.22*		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)
10.23*		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)
10.24*		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)
10.25*		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)
10.26*		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)
10.27*		Form of Change of Control Agreement with future officers of the Company. (Filed as Exhibit 10.02 to OGE Energy’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12579) and incorporated by reference herein)
10.28*		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)
10.29*		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)
10.30*		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)
10.31*		Employment Arrangement between OGE Energy and Sean Trauschke, the Company’s Chief Financial Officer. (Filed as Exhibit 10.01 to OGE Energy’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12579) and incorporated by reference herein)
10.32*		Change of Control Arrangement between OGE Energy and Sean Trauschke, the Company’s Chief Financial Officer. (Filed as Exhibit 10.01 to OGE Energy’s Form 8-K filed May 8, 2009 (File No. 1-12579) and incorporated by reference herein)
10.33		Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s OU Spirit application. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed December 2, 2009 (File No. 1-12579) and incorporated by reference herein)
10.34*		Amendment No. 1 to OGE Energy’s Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy’s Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein)
10.35*		Amendment No. 1 to OGE Energy’s Deferred Compensation Plan. (Filed as Exhibit 10.41 to OGE Energy’s Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein)

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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 July 30, 2009 (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 99.02 to OGE Energy’s Form 8-K filed May 27, 2009 (File No. 1-12579) and incorporated by reference herein)
99.02		Copy of OCC order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s OU Spirit application. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed October 21, 2009 (File No. 1-12579) and incorporated by reference herein)

* Represents executive compensation plans and arrangements,

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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, 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

Year Ended December 31, 2009

Reserve for Uncollectible Accounts	$	2.3	$	3.1	$	---	$	3.7 (A)	$	1.7

(A) Uncollectible accounts receivable written off, net of recoveries.

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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 18th day of February, 2010.

	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 18, 2010
/ s / Sean Trauschke
Sean Trauschke	Principal Financial Officer; and	February 18, 2010

/ s / Scott Forbes
Scott Forbes	Principal Accounting Officer.	February 18, 2010

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 18, 2010

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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.

115

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OKLAHOMA GAS & ELECTRIC CO Reports

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