Edgar Filing: OGE ENERGY CORP.

redone10k.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

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: 1-12579

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

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

Title of each class

Common Stock

Rights to Purchase Series A Preferred Stock

Name of each exchange on which registered

New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No o

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 x Accelerated Filer o

Non-Accelerated Filer o (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 $2,725,078,180 based on the number of shares held by non-affiliates (96,224,512) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $28.32.

At January 31, 2010, 97,048,304 shares of common stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company’s 2010 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.

OGE ENERGY CORP.

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
Electric Operations – OG&E	4
General	4
Regulation and Rates	6
Rate Structures	10
Fuel Supply and Generation	11
Natural Gas Pipeline Operations – Enogex	12
Environmental Matters	21
Finance and Construction	24
Employees	27
Access to Securities and Exchange Commission Filings	27

Item 1A. Risk Factors	27

Item 1B. Unresolved Staff Comments	38

Item 2. Properties	39

Item 3. Legal Proceedings	41

Item 4. Submission of Matters to a Vote of Security Holders	44
Executive Officers of the Registrant	44

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities	47

Item 6. Selected Financial Data	49

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	50

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	91

Item 8. Financial Statements and Supplementary Data	94

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	155

Item 9A. Controls and Procedures	155

Item 9B. Other Information	159

Part III

Item 10. Directors, Executive Officers and Corporate Governance	159

Item 11. Executive Compensation	159

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters	159

Item 13. Certain Relationships and Related Transactions, and Director Independence	159

Item 14. Principal Accounting Fees and Services	159

Part IV

Item 15. Exhibits, Financial Statement Schedules	159

Signatures	167

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 OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) and its subsidiaries to access the capital markets and obtain financing on favorable terms;

Ÿ	prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;

Ÿ	business conditions in the energy and natural gas midstream industries;

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;

Ÿ	the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; 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

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. For financial information regarding these segments, see Note 12 of Notes to Consolidated Financial Statements. The Company was incorporated in August 1995 in the state of Oklahoma and its principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.

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

Enogex LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Prior to January 1, 2008, Enogex owned OGE Energy Resources, Inc. (“OERI”), whose primary operations are in natural gas marketing. On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC. Enogex is a Delaware single-member limited liability company. Effective July 1, 2009, Enogex LLC formed a new entity, Enogex Gathering & Processing LLC, a wholly-owned subsidiary of Enogex, for purposes of holding the membership interests of Enogex Gas Gathering LLC, Enogex Products LLC (“Products”) and Enogex Atoka LLC, which were previously direct wholly-owned subsidiaries of Enogex LLC.

In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture, conducting business as Tallgrass Transmission L.L.C. (“Tallgrass”), to construct high-capacity transmission line projects. The Company owns 50 percent of Tallgrass. Tallgrass is intended to allow the participating companies to lead development of renewable wind by sharing capital costs associated with transmission construction. Tallgrass’ initial projects could include 765 kilovolt (“kV”) lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. A Southwest Power Pool (“SPP”) study estimates cost for the two projects if constructed as 765 kV lines to be approximately $500 million, of which OGE Energy’s portion would be approximately $250 million. See “Regulation and Rates – Recent Regulatory Matters – Tallgrass Joint Venture” for a further discussion of Tallgrass.

Company Strategy

The Company’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream natural gas business. The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s financial objectives from 2010 through 2012 include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis as well as an annual dividend growth rate of two percent subject to approval by the Company’s Board of Directors. The target payout ratio for the Company is to pay out as dividends no more than 60 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of the Company’s shareholder base, the Company’s financial position, the Company’s growth targets, the composition of the Company’s assets and investment opportunities. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range

of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

OG&E has been focused on increased investment 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 OG&E’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, OG&E 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, OG&E 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, OG&E 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, OG&E 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, OG&E received notification from the DOE that its grant had been accepted by the DOE;

Ÿ	in 2008, OG&E 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, OG&E received SPP approval to build four 345 kV transmission lines referred to as “Balanced Portfolio 3E”, which OG&E 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, OG&E signed power purchase agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma which OG&E intends to add to its power-generation portfolio by the end of 2010. OG&E 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 OG&E’s wind portfolio; and

OG&E’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.

OG&E continues to pursue additional renewable energy and the construction of associated transmission facilities required to support this renewable expansion. OG&E also is promoting Demand Side Management programs to encourage more efficient use of electricity. See “Recent Regulatory Matters – OG&E Conservation and Energy Efficiency Programs” for a further discussion. If these initiatives are successful, OG&E 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 existing OG&E power plants to help meet OG&E’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Laws and Regulations” and Note 14 of Notes to Consolidated Financial Statements.

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects, increased utilization of existing assets and strategic acquisitions. Enogex also plans to continue to add additional fee-based business to its portfolio as opportunities become available. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Enogex expects to accomplish this diversification

either by undertaking organic growth projects or through strategic acquisitions. Over the past several years, Enogex has been able to take advantage of numerous organic growth projects within its existing footprint including:

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

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

In addition to focusing on growing its earnings and improving cash flow, Enogex intends to continue to prudently manage its business and execute on organic growth initiatives. The Company’s business strategy is to continue maintaining the diversified asset position of OG&E and Enogex so as to provide competitive energy products and services to customers primarily in the south central United States. The Company will continue to focus on those products and services with limited or manageable commodity price exposure. Also, the Company believes that many of the risk management practices, commercial skills and market information available from OERI provide value to all of the Company’s businesses.

ELECTRIC OPERATIONS - OG&E

General

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. At December 31, 2009, four other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E 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 OG&E serves, 243 are located in Oklahoma and 26 in Arkansas. OG&E 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.

OG&E’s system control area peak demand during 2009 was approximately 6,418 MWs on July 13, 2009. OG&E’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 OG&E’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.

OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.

Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy.

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

OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, 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 OG&E’s facilities and operations. For the year ended December 31, 2009, approximately 89 percent of OG&E’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 OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E, (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

Recent Regulatory Matters

OG&E 2009 Oklahoma Rate Case Filing. On February 27, 2009, OG&E 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 OG&E’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 OG&E’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 OG&E’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. OG&E 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.

OG&E Arkansas Rate Case Filing. In August 2008, OG&E 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 OG&E 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 OG&E’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. OG&E implemented the new electric rates effective June 1, 2009.

OG&E OU Spirit Wind Power Project. OG&E 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 OG&E’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, OG&E 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 OG&E 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 OG&E’s customers. The rider will be in effect until OU Spirit is added to OG&E’s regulated rate base as part of OG&E’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 OG&E’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, OG&E 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, OG&E 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 OG&E receiving a final LGIA. On May 29, 2009, OG&E executed an interim LGIA, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. In connection with the interim LGIA, OG&E 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 OG&E 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, OG&E 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, OG&E 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.

OG&E Renewable Energy Filing. OG&E 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, OG&E issued a request for proposal (“RFP”) to wind developers for construction of up to 300 MWs of new capability, which OG&E intends to add to its power-generation portfolio by the end of 2010. In June 2009, OG&E 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, OG&E 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 OG&E will purchase their electric output. On October 30, 2009, OG&E 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 OG&E to recover the costs of the power purchase agreements through OG&E’s fuel adjustment clause. On January 5, 2010, OG&E received an order from the OCC approving the power purchase agreements and authorizing OG&E to recover the costs of the power purchase agreements through OG&E’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 OG&E’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. OG&E will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.

OG&E Windspeed Transmission Line Project. OG&E 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, OG&E 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 OG&E’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 OG&E 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, OG&E 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, OG&E received SPP approval to begin construction of the transmission line and the associated Woodward District EHV substation. In 2009, OG&E received a favorable outcome in five local court cases challenging OG&E’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. OG&E 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 OG&E to construct approximately 44 miles of new 345 kV transmission line which will originate at the existing OG&E 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, OG&E received notification from the SPP to begin construction on approximately 50 miles of new 345 kV transmission line and substation upgrades at OG&E’s Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative (“WFEC”) assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by the WFEC. The new line will extend from OG&E’s Sunnyside substation near Ardmore, Oklahoma, approximately 100 miles to the Hugo substation owned by the WFEC near Hugo, Oklahoma. OG&E 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 OG&E 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 OG&E and includes: (i) construction of approximately 120 miles of transmission line from OG&E’s Seminole substation in a northeastern direction to OG&E’s Muskogee substation at a cost of approximately $131 million for OG&E, which is expected to be in service by December 2014, (ii) construction of approximately 72 miles of transmission line from OG&E’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 OG&E, which is expected to be in service by April 2014, (iii) construction of approximately 38 miles of transmission line from OG&E’s Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of approximately $41 million for OG&E, 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 OG&E’s portion of the Cimarron-Lawton East Side 345 kV line at an estimated cost of approximately $8 million for OG&E, which is expected to be in service by December 2012. On June 19, 2009, OG&E received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, OG&E responded to the SPP that OG&E 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.”

OG&E Conservation and Energy Efficiency Programs. In June and September 2009, OG&E 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 OG&E customers. Several programs are proposed in these applications, ranging from residential weatherization to commercial lighting. In seeking approval of these new programs, OG&E also seeks recovery of the program and related costs through a rider that

would be added to customers’ electric bills. In Arkansas, OG&E’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, OG&E’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 OG&E 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 OG&E 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. OG&E received an order in the OCC matter on February 10, 2010.

OG&E 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, OG&E filed a grant request on August 4, 2009 for $130 million with the DOE to be used for the Smart Grid application in OG&E’s service territory. On October 27, 2009, OG&E 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. OG&E 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, OG&E requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for OG&E’s workforce. Recipients of the grant are expected to be announced in the first quarter of 2010.

Tallgrass Joint Venture. In July 2008, Tallgrass was formed to construct high-capacity transmission line projects. The Company owns 50 percent of Tallgrass. Tallgrass is intended to allow the participating companies to lead development of renewable wind by sharing capital costs associated with transmission construction. The Tallgrass projects are subject to creation by the SPP of a cost allocation method that would spread the total cost across the SPP region. OGE Energy is uncertain as to the timing of when the cost allocation method will be developed and approved. OGE Energy filed an application with the FERC in October 2008 for cost recovery of these projects subject to SPP and FERC approval for these projects. On December 2, 2008, the FERC granted Tallgrass’ request for transmission rate incentives for the initial projects, established a base ROE for initial projects, approved certain accounting treatments for the initial projects and set the formula rate and accompanying protocols for hearing and settlement discussions. Tallgrass’ initial projects could include 765 kV lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. An SPP study estimates the cost for the two projects if constructed as 765 kV lines to be approximately $500 million, of which OGE Energy’s portion would be approximately $250 million. The capital expenditures related to the Tallgrass projects discussed above are excluded from 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.” The SPP continues to review the initial Tallgrass projects and has not made a final determination whether these projects should be built. The SPP is reviewing these projects as a portion of the list of “Priority Projects” and the SPP is expected to make decisions on these projects as to timing and voltage in the second quarter of 2010. If the SPP determines that the above 765 kV projects should be 345 kV projects, these projects are expected to be completed by OG&E. In December 2009, the Tallgrass agreement was amended between the joint venture owners to expand the joint venture from the two potential 765kV projects discussed above to also include any potential 765 kV projects in Oklahoma that any subsidiary of the joint venture partners has the right to construct. The period of the agreement was established for seven years unless earlier terminated via the conditions precedent, which expire in December of 2011.

See Note 14 of Notes to Consolidated 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 OG&E’s fuel adjustment clause.

Regulatory Assets and Liabilities

OG&E, 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.

OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.

At December 31, 2009 and 2008, OG&E 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 Consolidated 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

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

OG&E 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 OG&E’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and is available as a voluntary option to all of OG&E’s Oklahoma retail customers. OG&E’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 OG&E as boiler fuel. Another program being offered to OG&E’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 OG&E’s system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.

OG&E also has two rate classes, Public Schools-Demand and Public Schools Non-Demand, that will provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E 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, OG&E implemented a military base rider that demonstrates Oklahoma’s continued commitment to our military partners.

The previously discussed rate options, coupled with OG&E’s other rate choices, provide many tariff options for OG&E’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. OG&E’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 OG&E’s customers for many years to come.

Arkansas

OG&E’s standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers (either positive or negative) the actual cost of fuel as compared to the fuel component in OG&E’s most recently approved rate case. OG&E’s Arkansas rate case order in May 2009 allows implementation of OG&E’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. OG&E 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 OG&E. The day-ahead price is based on OG&E’s projected next day hourly operating costs.

Fuel Supply and Generation

During 2009, approximately 60 percent of the OG&E-generated energy was produced by coal-fired units, 38 percent by natural gas-fired units and two percent by wind-powered units. Of OG&E’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 OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. 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 13 of Notes to Consolidated 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 OG&E’s fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.

Coal

All of OG&E’s coal-fired units, with an aggregate capability of approximately 2,570 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E purchases coal primarily under contracts expiring in years 2010, 2011 and 2015. In 2009, OG&E 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, OG&E’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 13 of Notes to Consolidated Financial Statements.

In August 2009, OG&E 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 OG&E’s projected coal requirements during that timeframe. Additional coal supplies to fulfill OG&E’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 OG&E in the future, including its utilization of coal.

Natural Gas

In August 2009, OG&E 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 OG&E’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 OG&E’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.

OG&E utilizes a natural gas storage facility for storage services that allows OG&E 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 OG&E. At December 31, 2009, OG&E had approximately 1.9 million MMBtu’s in natural gas storage valued at approximately $7.3 million.

Wind

OG&E’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 OG&E entered into with FPL Energy that expires in 2018.

OG&E 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, OG&E issued an RFP to wind developers for construction of up to 300 MWs of new capability which OG&E intends to add to its power-generation portfolio by the end of 2010. As part of this RFP process, on September 29, 2009, OG&E announced that 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 OG&E will purchase their electric output. On January 5, 2010, OG&E received an order from the OCC approving the power purchase agreements and authorizing OG&E to recover the costs of the power purchase agreements through OG&E’s fuel adjustment clause.

Safety and Health Regulation

OG&E 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 OG&E’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.

NATURAL GAS PIPELINE OPERATIONS - ENOGEX

Overview

Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.

Transportation and Storage

General

Enogex LLC owns and operates approximately 2,181 miles of intrastate natural gas transportation pipelines. Enogex also owns and operates two underground storage facilities currently being operated at a working gas level of approximately 24 billion cubic feet (“Bcf”). Enogex provides fee-based firm and interruptible transportation services on both an intrastate basis and pursuant to Section 311 of the Natural Gas Policy Act (“NGPA”) on an interstate basis. Enogex’s obligation to provide firm transportation service means that it is obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on Enogex’s part, the shipper pays a specified demand or reservation charge, whether or not it utilizes the capacity. In most intrastate firm contracts, the shipper also pays a transportation or commodity charge with respect to quantities actually transported by Enogex. Enogex’s obligation to provide interruptible transportation service means that it is obligated to transport natural gas nominated by the shipper only to the extent that it has available capacity. For this service, the shipper pays no demand or reservation charge but pays a transportation or commodity charge for quantities actually shipped. Enogex derives a substantial portion of its transportation revenues from firm transportation services and leased capacity. To the extent pipeline capacity is not needed for such firm transportation services and leased capacity, Enogex offers interruptible interstate transportation services pursuant to Section 311 of the NGPA as well as interruptible intrastate transportation services.

Enogex delivers natural gas to most interstate and intrastate pipelines and end-users connected to its systems from the Arkoma and Anadarko basins (including recent growth activity in the Granite Wash play, Woodford Shale play and Atoka play in western Oklahoma and the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is

located in the Texas Panhandle). At December 31, 2009, Enogex was connected to 13 third-party natural gas pipelines and had 64 interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative, CenterPoint Energy Gas Transmission Co., El Paso Natural Gas Pipeline, Quest Pipelines (KPC), Ozark Gas Transmission, L.L.C., Gulf Crossings Pipeline Company LLC and Midcontinent Express Pipeline, LLC (“MEP”). Further, Enogex is connected to 24 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma.

Enogex owns and operates two underground natural gas storage facilities in Oklahoma, the Wetumka Storage Facility and the Stuart Storage Facility. These storage facilities are currently being operated at a working gas level of approximately 24 Bcf and have approximately 650 million cubic feet per day (“MMcf/d”) of maximum withdrawal capability and approximately 650 MMcf/d of injection capability. Enogex offers both fee-based firm and interruptible storage services. Storage services offered under Section 311 of the NGPA are pursuant to terms and conditions specified in Enogex’s Statement of Operating Conditions (“SOC”) for gas storage and at market-based rates.

Enogex uses its storage assets to meet its contractual obligations under certain load following transportation and storage contracts, including its transportation agreement with OG&E. Enogex also periodically conducts an open season to solicit commitments for contracted storage capacity and deliverability to third parties.

Customers and Contracts

Enogex’s major transportation customers are OG&E and Public Service Company of Oklahoma (“PSO”), the second largest electric utility in Oklahoma. Enogex provides gas transmission delivery services to all of PSO’s natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract and the OG&E contract provide for a monthly demand charge plus variable transportation charges including fuel. The PSO contract expires January 1, 2013, unless extended. The stated term of the OG&E contract expired April 30, 2009, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2010, the contract will remain in effect at least through April 30, 2011. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex has been providing natural gas storage services to OG&E since August 2002 when it acquired the Stuart Storage Facility. Demand for natural gas on Enogex’s system is usually greater during the summer, primarily due to demand by gas-fired electric generation facilities to serve residential and commercial electricity requirements. In 2009, 2008 and 2007, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $116.8 million, $104.4 million and $103.9 million, respectively, of which approximately $47.5 million, $47.5 million and $47.4 million, respectively, was attributed to OG&E and approximately $15.3 million, $15.3 million and $13.3 million, respectively, was attributed to PSO. Revenues from Enogex’s firm intrastate transportation and storage contracts represented approximately 32 percent of Enogex’s consolidated gross margin on revenues (“gross margin”) in 2009, 27 percent in 2008 and 29 percent in 2007.

Competition

Enogex’s transportation and storage assets compete with numerous interstate and intrastate pipelines, including several of the interconnected pipelines discussed above, and storage facilities in providing transportation and storage services for natural gas. The principal elements of competition are rates, terms of services, flexibility and reliability of service. Natural gas-fired electric generation facilities contribute their highest value when they have the capability to provide load following service to the customer (i.e., the ability of the generation facility to regulate generation to respond to and meet the instantaneous changes in customer demand for electricity). While the physical characteristics of natural gas-fired electric generation facilities are known to provide quick start-up, on-line functionality and the ability to efficiently provide varying levels of electric generation relative to other forms of generation, a key part of their effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond quickly to meet their corresponding fluctuating fuel needs. We believe that Enogex is well positioned to compete for the needs of these generators due to the ability of its transportation and storage assets to provide no-notice load following service.

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

Regulation

The transportation rates charged by Enogex for transporting natural gas in interstate commerce are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years. The rate review may, but will not necessarily, involve an administrative-type hearing before a FERC Staff panel and an administrative appellate review. In the past, Enogex has successfully settled, rather than litigated, its Section 311 rate cases. Enogex currently has two zones under its Section 311 rate structure – an East Zone and a West Zone. Enogex historically offered only interruptible Section 311 service in both zones. As of April 1, 2009, Enogex also began to offer firm Section 311 service in the East Zone.

For Section 311 service, Enogex may charge up to its maximum established zonal East and West interruptible transportation rates for interruptible transportation in one zone or cumulative maximum rates for transportation in both zones. Enogex may charge up to its maximum established firm rate for firm Section 311 transportation in its East Zone. Finally, Enogex may charge the applicable fixed zonal fuel percentage(s) for the fuel used in transporting natural gas under Section 311 on the Enogex system. The fuel percentages are the same for firm and interruptible Section 311 services.

Enogex FERC Section 311 2007 Rate Case

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for Section 311 service in the East Zone and West Zone. Enogex’s filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some also filed protests. Settlement discussions have continued between the parties. With respect to the 2007 Section 311 rate case, Enogex did not place the increased rates set forth in its October 2007 rate filing into effect but rather continued to provide interruptible Section 311 service under the maximum Section 311 rates for both zones approved by the FERC in the previous rate case. Neither a final settlement nor an order from the FERC has been entered for the 2007 triennial filing. With the filing of Enogex’s 2009 rate case discussed below, the rate period for the 2007 rate case became a limited locked-in period from January 2008 through May 2009.

On November 13, 2007, one of the protesting intervenors in the 2007 rate case filed to consolidate the 2007 rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the new MEP pipeline and to lease firm capacity from Enogex. Enogex and MEP separately opposed this intervenor’s protests and assertions in its initial and subsequent pleadings. On July 25, 2008, the FERC issued an order approving the MEP project including the approval of a limited jurisdiction certificate authorizing the Enogex lease agreement with MEP denying the request for consolidation and rejecting all claims raised by protestors regarding the lease agreement. Accordingly, Enogex proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, the same protestor sought rehearing which the FERC denied. Enogex commenced service to MEP under the lease agreement on June 1, 2009. On July 16, 2009, the protestor filed, with the United States Court of Appeals for the District of Columbia Circuit, a petition for review of the FERC’s orders approving the MEP construction and the MEP lease of capacity from Enogex requesting that such orders be modified or set aside on the grounds that they are arbitrary, capricious and contrary to law. The petitioner, the FERC and intervening parties, including Enogex, have been given an opportunity to brief the issues. Enogex expects to participate in the filing of a joint intervenors’ brief in support of the FERC’s order in this matter, which final briefing is scheduled to be completed in the third quarter of 2010.

Enogex FERC Section 311 2009 Rate Case

On March 27, 2009, Enogex filed a petition for rate approval with the FERC to set the maximum rates for a new firm East Zone Section 311 transportation service and to revise the rates for its existing East and West Zone interruptible Section 311 transportation service. In anticipation of offering this new service, Enogex also filed with the FERC, as required by the FERC’s regulations, a revised SOC Applicable to Transportation Services to describe the terms, conditions and operating arrangements for the new service. Enogex made the SOC filing on February 27, 2009.

Enogex began offering firm East Zone Section 311 transportation service on April 1, 2009. The revised East and West Zone zonal rates for the Section 311 interruptible transportation service became effective June 1, 2009. The rates for the firm East Zone Section 311 transportation service and the increase in the rates for East and West Zone and interruptible Section 311 service are being collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the SOC filing and some additionally filed protests. Enogex filed answers to the interventions and protests in both matters. The FERC Staff served data requests on Enogex seeking additional information regarding various aspects of the filing and Enogex has submitted responses. On August 19, 2009, the FERC issued an order extending the time for action until it can make a determination whether Enogex’s rates are fair and equitable or until the

FERC determines that formal proceedings are necessary. The August 19, 2009 order also directed the FERC Staff to report to the FERC by December 29, 2009 on the status of settlement negotiations. On January 4, 2010, the FERC Staff submitted its initial settlement offer (“Offer”) proposing various adjustments to Enogex’s filed cost of service. Comments in response to the Offer were due on or before January 15, 2010. On January 14, 2010, Enogex asked the FERC Staff some clarifying questions regarding the Offer. Only Enogex and one intervenor filed comments on January 15, 2010, and each indicated that they were awaiting the FERC Staff’s responses to the questions raised by Enogex before submitting substantive comments. The FERC Staff responded to the questions on January 20, 2010. Enogex anticipates that settlement discussions will continue.

Enogex 2010 Fuel Filing

Pursuant to its SOC, Enogex makes an annual fuel filing at the FERC to establish the zonal fuel percentages for each calendar year. The tracker mechanism set out in the SOC establishes prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year. The collected fuel is later trued-up to actual usage and based on the value of the fuel at the time of usage.

On November 23, 2009, Enogex made its annual filing to establish fixed fuel percentages for its East Zone and West Zone for calendar year 2010 (“2010 Fuel Year”). On December 9, 2009, the FERC issued a notice establishing December 18, 2009 as the due date for any interventions and protests. Several parties filed interventions. No protests were filed, but two intervenors reserved the right to do so, contingent upon the outcome of additional discussions with Enogex. On December 30, 2009, the FERC issued a letter order directing Enogex to submit certain additional information by January 13, 2010. Enogex submitted the information requested by the FERC and is continuing to discuss the filing with the intervenors.

The FERC regulates Enogex’s Section 311 transportation and storage services but does not regulate Enogex’s gathering services or intrastate transportation services. A recent FERC order, Order 720A, provides that companies, such as Enogex, will be required, as of June 30, 2010 to post scheduled volume and design capacity information on a daily basis for eligible receipt and delivery points on applicable gathering and intrastate transportation facilities that meet the requirements established in the order. While the jurisdictional status of Enogex’s gathering and intrastate transportation services remains unchanged under this new regulation, the requirement of the FERC order to post this information subjects Enogex to the FERC’s review of the requirements of this order. In addition, the OCC, the APSC and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to Enogex which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service.

Certain of Enogex’s pipeline operations are subject to various state and Federal safety and environmental and pipeline transportation laws. For example, the U.S. Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for its applicable pipelines. During 2009, Enogex incurred approximately $10.8 million of capital expenditures and operating costs for pipeline integrity management. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $34.2 million between 2010 and 2014 in connection with pipeline integrity management. The estimated capital expenditures and operating costs include Enogex’s estimates for the assessment, remediation and prevention or other mitigation that may be determined to be necessary. At this time, Enogex cannot predict the ultimate costs of its integrity management program and compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary. Enogex will continue to assess, remediate and maintain the integrity of its pipelines. The results of these activities could cause Enogex to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

Recent System Expansions

Over the past several years, Enogex has initiated multiple organic growth projects to increase capacity across its system.

In December 2006, Enogex entered into a firm capacity lease agreement with MEP for a primary term of 10 years (subject to possible extension) that gives MEP and its shippers access to capacity on Enogex’s system. The quantity of capacity subject to the MEP lease agreement is currently 272 MMcf/d, with the quantity ultimately to be leased subject to being increased by mutual agreement pursuant to the lease agreement. In addition to MEP’s lease of Enogex’s capacity, the MEP project included construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. In support of the MEP lease agreement, Enogex constructed approximately 43 miles of 24-inch steel pipe in Woods and Major counties in Oklahoma, and added 24,000 horsepower of electric-driven compression in Bennington,

Oklahoma. Enogex’s capital expenditures allocated to its support of the MEP lease agreement were approximately $99 million. Enogex commenced service to MEP under the lease agreement on June 1, 2009.

In order to accommodate additional deliveries to Bennington, Oklahoma, Enogex is planning to add an incremental 13,800 horsepower of gas turbine compression at its Bennington compressor station, as well as other system upgrades. This project is expected to be in service in May 2010. The capital expenditures associated with these projects are expected to be approximately $24 million.

In 2009, Enogex began construction of an approximately 36-mile, 16-inch steel intrastate transportation pipeline and 3,750 horsepower of electric compression. This transmission pipeline, which is scheduled to be completed by October 2010, will provide gas delivery to a natural-gas fired electric generation facility being constructed by Associated Electric Cooperative, Inc. (“AECI”) near Pryor, Oklahoma. Up to approximately $64 million of Enogex’s construction costs are subject to reimbursement in full by AECI as the project progresses. Enogex does not anticipate that the amount of construction costs will exceed $64 million.

Gathering and Processing

General

Enogex provides well connect, gathering, measurement, treating, dehydration, compression and processing services for various types of producing wells owned by various sized producers who are active in the areas in which Enogex operates. Most natural gas produced at the wellhead contains natural gas liquids (“NGLs”). Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This high-content, or “rich,” natural gas is generally not acceptable for transportation in the nation’s transmission pipeline system or for commercial use. The streams of processable natural gas gathered from wells and other sources are gathered into Enogex’s gas gathering systems and are delivered to processing plants for the extraction of NGLs, leaving residual dry gas that meets transmission pipeline and commercial quality specifications. Enogex is active in the extraction and marketing of NGLs from natural gas. The liquids extracted include condensate liquids, marketable ethane, propane, butanes and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane.

Enogex’s gathering system includes approximately 5,846 miles of natural gas gathering pipelines with approximately 1.25 trillion British thermal units per day of average daily gathered volumes during 2009. Enogex owns and operates eight natural gas processing plants with a total inlet capacity of approximately 943 MMcf/d, has a 50 percent interest in and operates the Atoka natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and has contracted to have access to up to 50 MMcf/d in two third-party plants, all in Oklahoma. Where the quality of natural gas received dictates the removal of NGLs, such gas is aggregated through the gathering system to the inlet of one or more processing plants operated or utilized by Enogex. The resulting processed stream of natural gas is then delivered from the tailgate of each plant into Enogex’s intrastate natural gas transportation system. For the year ended December 31, 2009, Enogex extracted and sold approximately 493 million gallons of NGLs.

Enogex’s gathering and processing business has approximately 332,000 horsepower of owned compression. Enogex also has its own compression overhaul center and specialized compression workforce.

Enogex gathers and processes natural gas pursuant to a variety of arrangements generally categorized as “fee-based”, “percent-of-proceeds” and “percent-of-liquids” and “keep-whole” arrangements. Percent-of-proceeds, percent-of-liquids and keep-whole arrangements involve commodity price risk to Enogex because Enogex’s margin is based in part on natural gas and NGLs prices. Enogex seeks to mitigate its exposure to fluctuations in commodity prices in several ways, including managing its contract portfolio. In managing its contract portfolio, Enogex classifies its gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

Fee-Based Arrangements. Under these arrangements, Enogex generally is paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through Enogex’s system and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in Enogex’s fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At December 31, 2009, these arrangements accounted for approximately 20 percent of Enogex’s natural gas processed volumes.

Ÿ	Percent-of-Proceeds and Percent-of-Liquids Arrangements. Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system,

processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which Enogex shares in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which Enogex receives proceeds from the sale of NGLs or the NGLs themselves as compensation for its processing services as percent-of-liquids arrangements. Under percent-of-proceeds arrangements, Enogex’s margin correlates directly with the prices of natural gas and NGLs. Under percent-of-liquids arrangements, Enogex’s margin correlates directly with the prices of NGLs. At December 31, 2009, these arrangements accounted for approximately 45 percent of Enogex’s natural gas processed volumes.

Keep-Whole Arrangements. Enogex processes raw natural gas to extract NGLs and returns to the producer the full gas equivalent British thermal unit (“Btu”) value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. Enogex is entitled to retain the processed NGLs and to sell them for its own account. Accordingly, Enogex’s margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of Enogex’s keep-whole contracts include provisions that reduce its commodity price exposure, including conditioning floors (such as the default processing fee described below) that allow the keep-whole contract to be charged a fee if the NGLs have a lower value than their gas equivalent Btu value in natural gas. At December 31, 2009, these arrangements accounted for approximately 35 percent of Enogex’s natural gas processed volumes.

Enogex’s gathering and processing contracts typically contain terms and conditions that require a “default processing fee” in the event the gathered gas exceeds downstream interconnect specifications. Natural gas that is greater than 1,080 Btu per cubic foot coming out of wells must typically be processed before it can enter an interstate pipeline. The default processing fee stipulates a fee to be paid to the processor if the market for NGLs is lower than the gas equivalent Btu value of the natural gas that is removed from the stream. The default processing fee helps to minimize the risk of processing gas that is greater than 1,080 Btu per cubic foot when the price of the NGLs to be extracted and sold is less than the Btu value of the natural gas that Enogex otherwise would be required to replace.

Approximately 17 percent of the commercial grade propane produced at Enogex’s processing plants is sold on the local market. The balance of propane and the other NGLs produced by Enogex is delivered into pipeline facilities of a third party and transported to Conway, Kansas or Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane, which may be optionally produced at all of Enogex’s plants except the Roger Mills and Calumet plants, is also sold under contract or on the spot market.

Enogex’s large diameter, rich gas gathering pipelines in western Oklahoma are configured such that natural gas from the Wheeler County area in the Texas Panhandle can flow to the Cox City, Thomas or Calumet gas processing plants. These large-diameter “super-header” gathering systems of Enogex provide gas routing flexibility for Enogex to optimize the economics of its gas processing and to improve system utilization and reliability.

As Enogex experiences increased growth in regions such as the Woodford Shale play, Enogex will evaluate the need to expand its processing plants in order to meet the growing needs of its producer customers.

Customers and Contracts

The natural gas remaining after processing is primarily taken in kind by the producer customers into Enogex’s transportation pipelines for redelivery either: (i) to on-system customers such as the electric generation facilities of OG&E, PSO, other independent power producers and other end-users or (ii) into downstream interstate pipelines. Enogex’s NGLs are typically sold to NGLs marketers and end-users, its condensate liquid production is typically sold to marketers and refineries and its propane is typically sold in the local market to wholesale distributors. Enogex’s key natural gas producer customers include Chesapeake Energy Marketing Inc., Devon Gas Services, L.P., Apache Corporation, BP America Production Company and Samson Resources Company. During 2009, these five customers accounted for approximately 18.6 percent, 13.2 percent, 12.7 percent, 4.0 percent and 3.9 percent, respectively, of Enogex’s gathering and processing volumes. During 2009, Enogex’s top 10 natural gas producer customers accounted for approximately 66.6 percent of Enogex’s gathering and processing volumes.

Competition

Competition for natural gas supply is primarily based on efficiency and reliability of operations, customer service, proximity to existing assets, access to markets and pricing. Competition to gather and process non-dedicated gas is based on providing the producer with the highest total value, which is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enogex believes it will be able to continue to compete effectively. Enogex competes with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. Enogex’s primary competitors are master limited partnerships who are active in its region, including Atlas Pipeline Partners, L.P., Crosstex Energy LP, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., Hiland Partners, MarkWest Energy Partners, L.P. and Oneok Partners, L.P. In processing and marketing NGLs, Enogex competes against virtually all other gas processors extracting and selling NGLs in its market area.

Regulation

State regulation of natural gas gathering facilities generally includes various safety, environmental and nondiscriminatory rate and open access requirements and complaint-based rate regulation. Enogex may be subject to state common carrier, ratable take and common purchaser statutes. The common carrier and ratable take statutes generally require gatherers to carry, transport and deliver, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers that purchase gas to purchase without undue discrimination as to source of supply or producer. These statutes may have the effect of restricting Enogex’s right to decide with whom it contracts to purchase natural gas or, as an owner of gathering facilities, to decide with whom it contracts to purchase or gather natural gas.

Oklahoma and Texas have each adopted a form of complaint-based regulation of gathering operations that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering open access and rate discrimination. Texas has also adopted a complaint based regulation (H.B. 1920), known as the Lost and Unaccounted for Gas (“LUG”) Bill. The LUG Bill expands the types of information that can be requested and gives the Texas Railroad Commission the authority to make determinations and issue orders for purposes of preventing waste in specific situations. To date, neither the gathering nor LUG regulations have had a significant impact on Enogex’s operations in Oklahoma or Texas. However, Enogex cannot predict what effect, if any, either of these regulations might have on its gathering operations in Oklahoma or Texas in the future.

Enogex’s gathering operations could be adversely affected should they be subject in the future to the application of state or Federal regulation of rates and services. Enogex’s gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. Enogex cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Recent System Expansions

Over the past several years, Enogex has initiated multiple organic growth projects. Currently, in Enogex’s gathering and processing business, organic growth capital expenditures are focused on expansions on the east side of Enogex’s gathering system, primarily in the Woodford Shale play in southeastern Oklahoma and on the west side of Enogex’s gathering system, primarily in the Granite Wash play, Woodford Shale play and Atoka play in western Oklahoma and the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle.

Southeastern Oklahoma / East Side Expansions

Enogex is expanding in the Woodford Shale play and has several projects either completed or scheduled for completion in 2009 and 2010. For example, in December 2006, Enogex entered into a joint venture arrangement with Pablo Gathering, LLC, a subsidiary of Pablo Energy II, LLC, a Texas-based exploration and production company, which resulted in the formation of Atoka. Atoka constructed, owns and/or operates a gathering system and processing plant and related facilities relating to production in certain areas in southeastern Oklahoma. The gathering system and processing plant were placed in service during the third quarter of 2007. Enogex owns a 50 percent membership interest in Atoka and acts as the managing member and operator of the facilities owned by the joint venture. The joint venture plans to expand its gathering pipeline infrastructure in order to accommodate additional production in the area. The capital expenditures associated with the pipeline expansion of Atoka are expected to be approximately $7 million.

In February 2008, Enogex completed construction of a 20-mile pipeline project that connected Enogex’s Hughes, Coal and Pittsburgh County gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma. The gathering project created additional gathering capacity of 75 MMcf/d for customers desiring low-pressure services. The pipeline is complemented by approximately 16,000 horsepower of new gathering compression which was completed in the third quarter of 2008. Also, in June 2009, Enogex added approximately 16 miles of 20-inch steel pipe to its system with throughput capacity of approximately 300 MMcf/d. The capital expenditures associated with these projects were approximately $68 million.

Enogex plans to construct a new compressor station in Coal County, Oklahoma, as well as approximately 10 miles of gathering pipe and related treating facilities. The station would be designed to accommodate up to 6,700 horsepower of low pressure compression and would be supported by approximately five miles of 20-inch steel pipe and five miles of 12-inch steel pipe. The new compressor station would also include the lease or possible purchase of associated gas treating facilities for the incremental gas in this area. The initial 2,700 horsepower at the compressor station, and the gathering pipe, are expected to be completed in February 2010, with an incremental 2,700 horsepower expected to be in service by April 2010. The capital expenditures for this construction are expected to be between approximately $18 million and $25 million depending on whether Enogex leases or purchases the equipment.

Texas Panhandle / West Side Expansions

In August 2006, Enogex completed a project to expand its gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed Enogex to benefit from growth opportunities in that marketplace. Since the pipeline was put in service, Enogex has completed the construction of five new gas gathering compressor stations totaling approximately 26,500 horsepower of compression, and several miles of gathering pipe, including a new 16-inch line that extends the original pipeline project an additional 20 miles to the west. In August 2009, Enogex added another 8,000 horsepower of low pressure compression in Wheeler County, Texas. The capital expenditures associated with the additional horsepower of low pressure compression were approximately $18 million.

In order to accommodate the increased drilling activity in Canadian County, Oklahoma, Enogex completed construction of approximately six miles of 12-inch steel pipe and another 2,800 horsepower of compression capacity to its Grandview gathering project in 2009. The capital expenditures associated with the additional pipe and compression capacity were approximately $8 million.

Enogex completed construction of a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant was placed in service in late October 2009 and is processing new gas developments in the area. In support of this plant, Enogex has installed approximately 15 miles of gathering pipe, 2.5 miles of transmission pipe and 10,000 horsepower of inlet compression, as well as other system upgrades. The capital expenditures associated with these projects were approximately $77 million.

As additional support for the strong production needs surrounding Enogex’s new Clinton plant, Enogex plans to build an additional six miles of 16-inch high pressure gathering pipe and construct a new compressor station designed to handle 6,700 horsepower of single-stage compression. The initial 4,000 horsepower at the compressor station, and the high pressure gathering pipe, are expected to be in service in August 2010. The capital expenditures for this initial stage of the construction are expected to be approximately $14 million.

Enogex is planning to further expand its gathering infrastructure in 2010 in the Wheeler County, Texas area with the construction of approximately nine miles of 10-inch steel pipe and seven miles of 16-inch steel pipe, as well as the addition of approximately 2,700 horsepower of compression. The gathering pipelines are expected to be in service in May 2010, while the compression is expected to be operational by July 2010. The capital expenditures associated with this project are expected to be approximately $12 million.

Enogex is planning construction of approximately 26 miles of 16-inch steel pipe and five miles of 8-inch steel pipe located in Washita and Custer counties in Oklahoma. This project will provide additional high pressure gathering capacity to active producers in this growth area. This project is expected to be in service in September 2010. The capital expenditures associated with this project are expected to be approximately $19 million.

Enogex Additional Processing Capacity

In the fourth quarter of 2009, Enogex began taking delivery of components of a cryogenic processing plant which, when installed, will be expected to add another 120 MMcf/d of processing capacity to Enogex’s system. The capital

expenditures associated with the purchase of the new processing cryogenic plant are expected to be approximately $16 million and exclude any expenditures for installation and ancillary equipment.

Safety and Health Regulation

Certain of Enogex’s facilities are subject to Title 49 CFR Transportation Parts 191, 192, 195 and 199, including the Pipeline Safety Improvement Act of 2002 (“PSIA”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES”). The Pipeline Hazardous Materials Safety Administration (“PHMSA”) regulates safety requirements in the design, construction, operation and maintenance of applicable natural gas and hazardous liquid pipeline facilities. Both the PSIA and the PIPES require mandatory inspections and enforcement for all U.S. hazardous liquid and natural gas transportation pipelines, including some gathering lines in high population areas. The DOT has developed regulations implementing the PSIA that require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in high-consequence areas where threats pose the greatest risk to people and their property.

States may be preempted by Federal law from solely regulating pipeline safety but may assume responsibility for enforcing Federal intrastate pipeline regulations and inspection of intrastate pipelines. In the state of Oklahoma, the OCC’s Transportation Division, acting through the Pipeline Safety Department, administers the OCC’s intrastate regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline. The OCC develops regulations and other approaches to assure safety in design, construction, testing, operation, maintenance and emergency response to pipeline facilities. The OCC derives its authority over intrastate pipeline operations through state statutes and certification agreements with the DOT. A similar regime for safety regulation is in place in Texas and administered by the Texas Railroad Commission. Enogex’s natural gas pipelines have inspection and audit programs designed to maintain compliance with pipeline safety and pollution control requirements.

In addition, Enogex is subject to a number of Federal and state laws and regulations, including OSHA and comparable state statutes, whose purpose is to protect the safety and health of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the 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 Enogex’s operations and that this information be provided to employees, state and local government authorities and citizens. Enogex is also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Enogex has an internal program of inspection designed to monitor and enforce compliance with worker safety and health requirements. Enogex believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

MARKETING - OERI

General

OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers and reselling to pipelines, local distribution companies and end-users, including the electric generation sector. The geographic scope of marketing efforts has been focused largely in the mid-continent area of the United States. These markets are natural extensions of OERI’s business on the Enogex system. OERI contracts for pipeline capacity with Enogex and other pipelines to access multiple interconnections with the interstate pipeline system network that moves natural gas from the production basins primarily in the south central United States to the major consumption areas in Chicago, New York and other north central and mid-Atlantic regions of the United States.

OERI primarily participates in both intermediate-term markets (less than three years) and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on intermediate-term sales, short-term sales of natural gas are expected to continue to play a critical role in the overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function. OERI’s average daily sales volumes decreased from approximately 0.6 Bcf in 2008 to approximately 0.4 Bcf in 2009. This reflects selective deal execution to assure adequate margin in light of credit and other risks in the current commodity price and credit environment. OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by OERI by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the

over-the-counter market, subject to daily and monthly trading stop loss limits of $2.5 million and daily value-at-risk limits of $1.5 million in accordance with corporate policies.

On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Enogex has historically utilized, and expects to continue to utilize, OERI for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2009, 2008 and 2007, OERI recorded revenues from Enogex of approximately $45.4 million, $41.9 million and $95.2 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2009, 2008 and 2007, Enogex recorded revenues from OERI of approximately $165.5 million, $307.2 million, and $304.3 million, respectively, for the sale, at market rates, of natural gas. Enogex has paid, and expects to continue to pay, certain fees to OERI for providing natural gas marketing, hedging, risk management and other related services. OERI pays Enogex a fee for certain back office functions and administrative services.

Competition

OERI competes with major integrated oil companies, commercial banks, national and local natural gas marketers, distribution companies and marketing affiliates of interstate and intrastate pipelines in marketing natural gas. Competition for both natural gas supplies and natural gas sales is based primarily on reputation, accuracy, flexibility, products offered, credit support, the availability to transport gas to high-demand markets and the ability to obtain a satisfactory price for the natural gas.

For the year ended December 31, 2009, approximately 61.8 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers, of which approximately 36.8 percent was with affiliates of OERI. The remaining 38.2 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2009, approximately 69.6 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately 2.6 percent was to companies having less than investment grade ratings. The remaining 27.8 percent of OERI’s exposure is with privately held companies, municipals or cooperatives that were not rated by Standard & Poor’s. OERI applies internal credit analyses and policies to these non-rated companies.

Regulation

The price at which OERI buys and sells natural gas and NGLs is currently not subject to Federal regulation and, for the most part, is not subject to state regulation. However, OERI is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (“CFTC”). The FERC and CFTC hold substantial enforcement authority under the anti-market manipulation laws and regulations, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should OERI violate the anti-market manipulation laws and regulations, it could also be subject to related third party damage claims by, among other, marketers, royalty owners and taxing authorities.

ENVIRONMENTAL MATTERS

General

The activities of OG&E and Enogex 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 OG&E’s and Enogex’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes 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. OG&E and Enogex handle 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.

OG&E and Enogex believe that their 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. OG&E and Enogex 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 $3.5 million of the Company’s capital expenditures budgeted for 2010 are to comply with environmental laws and regulations, of which approximately $1.9 million and $1.6 million are related to OG&E and Enogex, respectively. Approximately $3.9 million of the Company’s capital expenditures budgeted for 2011 are to comply with environmental laws and regulations, of which approximately $2.3 million and $1.6 million are related to OG&E and Enogex, respectively. It is estimated that OG&E’s and Enogex’s total expenditures for capital, operating, maintenance and other costs associated with environmental quality will be approximately $20.9 million and $5.7 million, respectively, in 2010 as compared to approximately $19.9 million and $4.0 million, respectively, 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 it 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 13 of Notes to Consolidated Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

Hazardous Waste

OG&E’s and Enogex’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.

For OG&E, these laws impose strict “cradle to grave” requirements on generators regarding their treatment, storage and disposal of hazardous waste. OG&E 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 OG&E’s facilities remain conditionally exempt small quantity generators of hazardous waste.

For Enogex, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other waste associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial waste such as paint waste, waste solvents and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

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 OG&E is concerned. OG&E’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 OG&E and Enogex utilize various products and generate wastes that either are or otherwise contain CERCLA hazardous substances, OG&E and Enogex 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 OG&E or Enogex.

Enogex currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, transportation, compression, processing and storage of natural gas and NGLs. Although Enogex used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by Enogex. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbon or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Enogex could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators) or remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills).

Air Emissions

OG&E’s and Enogex’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, natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E and Enogex 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 OG&E and Enogex to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. OG&E and Enogex 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

OG&E’s and Enogex’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 OG&E’s and Enogex’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 OG&E and Enogex conduct business could have an adverse effect on their operations and demand for their services or products. OG&E 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. OG&E is a partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program and Enogex is a partner in the EPA Natural Gas STAR Program, both are voluntary programs 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 OG&E and Enogex 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 at OG&E and Enogex. 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 and commercial paper) 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 consolidated estimates of capital expenditures are approximately: 2010 - $660 million, 2011 - $620 million, 2012 - $565 million, 2013 - $495 million, 2014 - $420 million and 2015 - $385 million. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s businesses) 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
	Total		(2010)		(2011-2012)		(2013-2014)		5 years
OG&E Base Transmission	$	150	$	45	$	40	$	40	$	25
OG&E Base Distribution		1,320		235		430		435		220
OG&E Base Generation		205		30		70		70		35
OG&E Other		150		25		50		50		25
Total OG&E Base Transmission, Distribution,
Generation and Other		1,825		335		590		595		305
OG&E 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 OG&E Known and Committed Projects		815		165		460		180		10
Total OG&E (B)		2,640		500		1,050		775		315
Enogex (Base Maintenance and Known and Committed
Projects)		355		135		85		90		45
OGE Energy and OERI		150		25		50		50		25
Total Consolidated	$	3,145	$	660	$	1,185	$	915	$	385

(A) These capital expenditures are contingent upon OCC approval of OG&E’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 OG&E 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 additional incremental growth opportunities in transmission assets, wind generation assets and at Enogex, will be evaluated based upon their impact upon achieving the Company’s financial objectives. The capital expenditure projections related to Enogex in the table above reflect base market conditions at February 17, 2010 and do not reflect the potential opportunity for a set of growth projects that could materialize.

Enogex’s Refinancing of Long-Term Debt and Tender Offer

On June 24, 2009, Enogex issued $200 million of 6.875% 5-year senior notes in a transaction exempt from the registration requirements of the Securities Act of 1933. Enogex applied a portion of the net proceeds from the sale of the new notes to pay the purchase price in a tender offer for its 8.125% notes due January 15, 2010 with the remainder of the net proceeds being used to repay a portion of Enogex’s borrowings under its revolving credit agreement and for general corporate purposes. Pursuant to the tender offer, on July 23, 2009, Enogex purchased approximately $110.8 million principal amount of the 8.125% senior notes due January 15, 2010 and those repurchased notes were retired and cancelled.

On November 10, 2009, Enogex issued $250 million of 6.25% 10-year senior notes in a transaction exempt from the registration requirements of the Securities Act of 1933. Enogex applied the net proceeds from the sale of the new notes to repay borrowings under its revolving credit agreement, with any excess net proceeds being invested at the OGE Energy level. Enogex’s permanent use of the net proceeds from this debt issuance was to repay a portion of the $289.2 million outstanding aggregate principal amount of Enogex’s 8.125% senior notes, which matured on January 15, 2010. On January 15, 2010, the $289.2 million outstanding aggregate principal amount of Enogex’s 8.125% senior notes was repaid.

Pension and Postretirement Benefit Plans

During each of 2009 and 2008, the Company made contributions to its pension plan of approximately $50.0 million to help ensure that the pension plan maintains an adequate funded status. During 2010, the Company may contribute up to $50.0 million to its pension plan. 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 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 proceeds from the sales of common stock to the public through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”) or other offerings will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The short-term debt balance was approximately $175.0 million and $298.0 million at December 31, 2009 and 2008, respectively. The December 31, 2009 short-term debt balance of approximately $175.0 million is comprised entirely of outstanding commercial paper borrowings at OGE Energy. The December 31, 2008 short-term debt balance of approximately $298.0 million is comprised entirely of outstanding borrowings under OGE Energy’s revolving credit agreement. At December 31, 2009, there were no outstanding borrowings under Enogex’s revolving credit agreement. At December 31, 2008, Enogex had approximately $120.0 million in outstanding borrowings under its revolving credit agreement. Also, OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31, 2010. See Note 10 of Notes to the Consolidated Financial Statements for a discussion of the Company’s short-term debt activity. The Company has approximately $58.1 million and $174.4 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 and equity securities for sale by the Company and OG&E.

Expected Issuance of OG&E Long-Term Debt

OG&E 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.

Common Stock

The Company expects to issue between approximately $12 million and $15 million in its DRIP/DSPP in 2010. See Note 8 of Notes to Consolidated Financial Statements for a discussion of the Company’s common stock activity.

EMPLOYEES

The Company and its subsidiaries had 3,363 employees at December 31, 2009.

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

The Company’s web site address is www.oge.com. Through the Company’s web site under the heading “Investor Relations”, “SEC Filings,” the Company makes available, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the 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 “OGE Energy”, “we”, “our” and “us” refer to OGE Energy Corp., “OG&E” refers to our subsidiary Oklahoma Gas and Electric Company and “Enogex” refers to our subsidiary Enogex LLC and its subsidiaries. In addition to the other information in this Annual Report on Form 10-K and other documents filed by us and/or our subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS

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

We are subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences our operating environment and OG&E’s ability to fully recover its costs from utility customers. With rising fuel costs, recoverability of under recovered amounts from our customers is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to fully recover costs related to providing energy and utility services to our customers.

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.

OG&E’s 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.

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

OG&E operates in Oklahoma and western Arkansas and is subject to 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, consolidated 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 OG&E’s 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.

OG&E reports quarterly its carbon dioxide emissions from its generating stations under the EPA’s acid rain program and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its 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 13 of Notes to Consolidated 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 consolidated 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. OG&E’s operations are not sensitive to potential future sea-level rise as it does not operate in coastal areas. However, OG&E’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 OG&E system, so OG&E 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 OG&E’s cost of providing service. OG&E’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 OG&E’s service territory, OG&E 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 OG&E’s generating resources. At the same time, OG&E 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), the Company may be adversely impacted. A declining economy could adversely impact the overall financial health of the Company 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 for OG&E 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 OG&E’s 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. OG&E currently provides 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 construction by Enogex of additions or modifications to its existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond Enogex’s control and may require the expenditure of significant amounts of capital. These projects, once undertaken, may not be completed on schedule or at the budgeted cost, or at all. Moreover, Enogex’s revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if Enogex expands an existing pipeline or constructs a new pipeline, the construction may occur over an extended period of time, and Enogex may not receive any material increases in revenues or cash flows until the project is completed. In addition, Enogex may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since Enogex is not engaged in the exploration for and development of natural gas, Enogex often does not have access to third-party estimates of potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enogex relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect Enogex’s results of operations, consolidated financial position and cash flows. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and Enogex may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, Enogex’s consolidated financial position, results of operations and cash flows could be adversely affected.

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

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP RTO and has transferred operational authority (but not ownership) of OG&E’s transmission facilities to the SPP RTO. The SPP RTO implemented a regional energy imbalance service market on February 1, 2007. OG&E has participated, and continues to participate, in the SPP energy imbalance service market to aid in the optimization of its physical assets to serve OG&E’s customers. OG&E has 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. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Consolidated Financial Statements. OG&E’s revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP RTO.

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

We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to 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 consolidated financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows.

A change in the jurisdictional characterization of some of Enogex’s assets by Federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Enogex’s natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, but the FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking and capacity release and its promotion of market centers, may indirectly affect intrastate markets. In recent years, the FERC has aggressively pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure that the FERC will continue to pursue these same objectives as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business.

Enogex’s natural gas transportation and storage operations are subject to regulation by the FERC pursuant to Section 311 of the NGPA, which could have an adverse impact on its ability to establish transportation and storage rates that would allow it to recover the full cost of operating its transportation and storage facilities, including a reasonable return, and an adverse impact on its consolidated financial position, results of operations or cash flows.

The FERC has jurisdiction over transportation rates charged by Enogex for transporting natural gas in interstate commerce under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years. See Note 14 of Notes to Consolidated Financial Statements for a further discussion of Enogex’s FERC Section 311 proceedings. There can be no assurance that the FERC will approve Enogex’s requested rates.

Enogex’s natural gas transportation, storage and gathering operations are subject to regulation by agencies in Oklahoma and Texas, and that regulation could have an adverse impact on its ability to establish rates that would allow it to recover the full cost of operating its facilities, including a reasonable return, and its consolidated financial position, results of operations or cash flows.

State regulation of natural gas transportation, storage and gathering facilities generally focuses on various safety, environmental and, in some circumstances, nondiscriminatory access requirements and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Enogex’s natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Enogex’s gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on Enogex’s operations, but Enogex could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect Enogex’s business. Any such state regulation could have an adverse impact on Enogex’s business and its consolidated financial position, results of operations or cash flows.

Enogex may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for applicable pipelines. The regulations require operators to:

Ÿ	identify potential threats to the public or environment, including “high consequence areas” on covered pipeline segments where a leak or rupture could do the most harm;

Ÿ	develop a baseline plan to prioritize the assessment of a covered pipeline segment;

Ÿ	gather data and identify and characterize applicable threats that could impact a covered pipeline segment;

Ÿ	discover, evaluate and remediate problems in accordance with the program requirements;

Ÿ	continuously improve all elements of the integrity program;

Ÿ	continuously perform preventative and mitigation actions;

Ÿ	maintain a quality assurance process and management-of-change process; and

Ÿ	establish a communication plan that addresses safety concerns raised by the DOT and state agencies, including the periodic submission of performance documents to the DOT.

During 2009, Enogex incurred approximately $10.8 million of capital expenditures and operating costs for pipeline integrity management. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $34.2 million between 2010 and 2014 in connection with pipeline integrity management. The estimated capital expenditures and operating costs include Enogex’s estimates for the assessment, remediation, prevention or other mitigation that may be determined to be necessary. At this time, we cannot predict the ultimate costs of its integrity management program and compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary. Enogex will continue to assess, remediate and maintain the integrity of its pipelines. The results of these activities could cause Enogex to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

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, consolidated 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, consolidated 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 the Company’s intent to comply with all applicable reliability rules and expediently correct a violation should it occur. OG&E is 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 consolidated 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 consolidated 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 and natural gas midstream 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.

Enogex does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

Enogex does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid

rights-of-way or if such rights-of-way lapse or terminate. Enogex obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies sometimes for a specific period of time. A loss of these rights, through Enogex’s inability to renew right-of-way contracts or otherwise, could cause Enogex to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, reduce its revenue and impair its cash flows.

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

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

Natural gas and NGLs prices are volatile, and changes in these prices could negatively affect Enogex’s and OERI’s results of operations and cash flows.

Enogex’s and OERI’s results of operations and cash flows could be negatively affected by adverse movements in the prices of natural gas and NGLs depending on factors that are beyond our control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquified natural gas and NGLs, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

Enogex’s keep-whole natural gas processing arrangements, which constituted approximately six percent of its gross margin and accounted for approximately 35 percent of its natural gas processed volumes during 2009, expose it to fluctuations in the pricing spreads between NGLs prices and natural gas prices. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis by replacing the Btu’s of the NGLs extracted from the production stream with Btu’s of natural gas. Therefore, if natural gas prices increase and NGLs prices do not increase by a corresponding amount, the processor has to replace the Btu’s of natural gas at higher prices and processing margins are negatively affected.

Enogex’s percent-of-proceeds and percent-of-liquids natural gas processing agreements constituted approximately seven percent of its gross margin and accounted for approximately 45 percent of its natural gas processed volumes during 2009. Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. Enogex refers to contracts in which it shares in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which it receives proceeds from the sale of NGLs or the NGLs themselves as compensation for its processing services as percent-of-liquids arrangements. These arrangements expose Enogex to risks associated with the price of natural gas and NGLs.

At any given time, Enogex’s overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that Enogex was a net buyer of natural gas) and a net long position in NGLs (meaning that Enogex was a net seller of NGLs). As a result, Enogex’s margins could be negatively impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

Because of the natural decline in production from existing wells connected to Enogex’s systems, Enogex’s success depends on its ability to gather new sources of natural gas, which depends on certain factors beyond its control. Any decrease in supplies of natural gas could adversely affect Enogex’s business and results of operations and cash flows.

Enogex’s gathering and transportation systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, Enogex’s cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on its gathering and transportation systems and

the asset utilization rates at its natural gas processing plants, Enogex must continually obtain new natural gas supplies. The primary factors affecting Enogex’s ability to obtain new supplies of natural gas and attract new customers to its assets depends in part on the level of successful drilling activity near these systems, Enogex’s ability to compete for volumes from successful new wells and Enogex’s ability to expand capacity as needed. If Enogex is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on its gathering, processing and transportation facilities would decline, which could have a material adverse effect on its business, results of operations and cash flows.

Enogex’s businesses are dependent, in part, on the drilling decisions of others.

All of Enogex’s businesses are dependent on the continued availability of natural gas production. Enogex does not have control over the level of drilling activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. The primary factor that impacts drilling decisions is natural gas prices. Natural gas prices reached relatively high levels in mid-2008 due to the impact of rising demand for natural gas but have returned to the near $4.50 per MMBtu level due to a rapid decline in demand for natural gas. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by Enogex’s gathering, processing and transportation facilities, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, access to credit, the ability of producers to obtain necessary drilling and other governmental permits, costs of steel and other commodities, geological considerations, demand for hydrocarbons, the level of reserves, other production and development costs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by Enogex’s assets, producers may choose not to develop those reserves.

The Company engages in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on its earnings and cash flows.

The Company is exposed to changes in commodity prices in its operations. To minimize the risk of commodity prices, the Company may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements, contractual long/short obligations, keep-whole positions, percent-of-liquids positions and inventories of natural gas.

Enogex has instituted a hedging program that is intended to reduce the commodity price risk associated with Enogex’s keep-whole and percent-of-liquids arrangements. At December 31, 2009, Enogex had hedged a majority of its expected non-ethane NGLs volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2010 and 2011. At December 31, 2009, Enogex had not hedged any of its expected ethane volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes. Enogex has the option to reject ethane if processing it is not economical. Management will continue to evaluate whether to enter into any new hedging arrangements, and there can be no assurance that Enogex will enter into any new hedging arrangements. Also, Enogex may seek in the future to further limit its exposure to changes in natural gas and NGLs commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms. To the extent Enogex hedges its commodity price and interest rate exposures, Enogex may forego the benefits that otherwise would be experienced if commodity prices or interest rates were to change in Enogex’s favor. In addition, even though management monitors Enogex’s hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or the hedging policies and procedures are not followed or do not work as planned.

Enogex depends on certain key natural gas producer customers for a significant portion of its supply of natural gas and NGLs. The loss of, or reduction in volumes from, any of these customers could result in a decline in its consolidated financial position, results of operations or cash flows.

Enogex relies on certain key natural gas producer customers for a significant portion of its natural gas and NGLs supply. During 2009, Chesapeake Energy Marketing Inc., Devon Gas Services, L.P., Apache Corporation, BP America Production Company and Samson Resources Company accounted for approximately 52.4 percent of Enogex’s natural gas and NGLs supply. The loss of the natural gas and NGLs volumes supplied by these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on Enogex’s consolidated financial position, results of operations and cash flows.

Enogex depends on two customers for a significant portion of its firm intrastate transportation and storage services. The loss of, or reduction in volumes from, either of these customers could result in a decline in Enogex’s transportation and storage services and its consolidated financial position, results of operations or cash flows.

Enogex provides firm intrastate transportation and storage services to several customers on its system. Enogex’s major customers are OG&E and PSO, which is the second largest electric utility in Oklahoma and serves the Tulsa market. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex provides gas transmission delivery services to all of PSO’s natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. In 2009, 2008 and 2007, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $116.8 million, $104.4 million and $103.9 million, respectively, of which approximately $47.5 million, $47.5 million and $47.4 million, respectively, was attributed to OG&E and approximately $15.3 million, $15.3 million and $13.3 million, respectively, was attributed to PSO. Enogex’s current contract with PSO expires January 1, 2013, unless extended. The stated term of Enogex’s current contract with OG&E expired April 30, 2009, but the contract will remain in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2010, the contract will remain in effect at least through April 30, 2011. The loss of all or even a portion of the intrastate transportation and storage services for either of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on Enogex’s consolidated financial position, results of operations and cash flows.

If third-party pipelines and other facilities interconnected to Enogex’s gathering, processing or transportation facilities become partially or fully unavailable, Enogex’s revenues and cash flows could be adversely affected.

Enogex depends upon third-party natural gas pipelines to deliver gas to, and take gas from, its transportation system. Enogex also depends on third-party facilities to transport and fractionate NGLs that it delivers to the third party at the tailgates of its processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. Since Enogex does not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within Enogex’s control. If any of these third-party pipelines or other facilities become partially or fully unavailable, Enogex’s revenues and cash flows could be adversely affected.

Enogex’s industry is highly competitive, and increased competitive pressure could adversely affect its consolidated financial position, results of operations or cash flows.

Enogex competes with similar enterprises in its respective areas of operation. Some of these competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than Enogex. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enogex provides to its customers. In addition, Enogex’s customers who are significant producers of natural gas may develop their own gathering, processing, transportation and storage systems in lieu of using Enogex’s. Enogex’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. All of these competitive pressures could have a material adverse effect on Enogex’s consolidated financial position, results of operations and cash flows.

Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, Enogex’s operations and financial results could be adversely affected.

Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, including:

Ÿ	damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, earthquakes, fires and other natural disasters and acts of terrorism;

Ÿ	inadvertent damage from third parties, including construction, farm and utility equipment;

Ÿ	leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and

Ÿ	fires and explosions.

These and other risks could result in substantial losses due to personal injury and loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of Enogex’s related operations. Enogex’s insurance is currently provided under the Company’s insurance

programs. Enogex is not fully insured against all risks inherent to its business. Enogex is not insured against all environmental accidents that might occur, which may include toxic tort claims. In addition, Enogex may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. Moreover, in some instances, significant claims by the Company may limit or eliminate the amount of insurance proceeds available to Enogex. As a result of market conditions, premiums and deductibles for certain of the Company’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. If a significant accident or event occurs that is not fully insured, it could adversely affect Enogex’s operations and financial results.

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, consolidated financial position or liquidity.

We have a qualified defined benefit retirement plan (“Pension Plan”) that covers substantially all of our employees hired before December 1, 2009. In October 2009, our Pension Plan and our 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 our Pension Plan and our 401(k) Plan. Also, effective December 1, 2009, our Pension Plan is no longer being offered to future employees of the Company. We also have 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 our assumptions at December 31, 2009, we expect to continue to make future contributions to maintain required funding levels. It is our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.

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. The Company has implemented all of the required changes as part of the Pension Protection Act as discussed in Note 11 of Notes to Consolidated Financial Statements.

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 consolidated 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, consolidated 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 and natural gas pipeline industry. The median age of utility and natural gas pipeline workers is significantly higher than the national average. Over the next three years, approximately 30 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 are a holding company with our primary assets being investments in our subsidiaries.

We are a holding company and thus our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to pay our dividends and service our indebtedness depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. At December 31, 2009, the Company and its subsidiaries had outstanding indebtedness and other liabilities of approximately $5.2 billion. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due on our indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiaries on the assets of these subsidiaries will have priority over our claims generally (except to the extent that we may be a creditor of the subsidiaries and our claims are recognized) and claims by our shareowners.

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

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

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

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

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

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 or the ratings of our subsidiaries’ will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances 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 facilities 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 revolving credit agreements for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:

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 consolidated financial position, results of operations and cash flows.

We are exposed to credit risks in our generation, retail distribution, pipeline and energy trading 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.

OG&E

OG&E 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 OG&E’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, OG&E purchased a 51 percent ownership interest in the Redbud Facility.
(E) Represents OG&E’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, OG&E’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. OG&E’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.

OG&E 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, OG&E 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.

Enogex

Enogex’s real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which Enogex’s interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for its operations. Certain of Enogex’s processing plants and related facilities are located on land Enogex owns in fee title, and Enogex believes that it has satisfactory title to these lands. The remainder of the land on which Enogex’s plants and related facilities are located is held by Enogex pursuant to ground leases between Enogex, as lessee, and the fee owner of the lands, as lessors. Enogex, or its predecessors, have leased these lands for many years without any material challenge known to us or Enogex relating to the title to the land upon which the assets are located, and Enogex believes that it has satisfactory leasehold estates to such lands. Enogex has no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by Enogex or to its title to any material lease, easement, right-of-way, permit or lease, and Enogex believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses.

Record title to some of Enogex’s assets may reflect names of prior owners until Enogex has made the appropriate filings in the jurisdictions in which such assets are located. Title to some of Enogex’s assets may be subject to encumbrances. We believe that none of such encumbrances should materially detract from the value of Enogex’s properties or our interest in those properties or should materially interfere with Enogex’s use of them in the operation of its business. Substantially all of Enogex’s pipelines are constructed on rights-of-way granted by the apparent owners of record of the properties. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the rights-of-way grants.

At December 31, 2009, Enogex and its subsidiaries owned: (i) approximately 5,846 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas, (ii) approximately 2,181 miles of intrastate natural gas transportation pipelines in Oklahoma and Texas, (iii) two underground natural gas storage facilities in Oklahoma operating at a working gas level of approximately 24 Bcf with approximately 650 MMcf/d of maximum withdrawal capacity and approximately 650 MMcf/d of injection capacity and (iv) eight operating natural gas processing plants, with a total inlet capacity of approximately 943 MMcf/d, a 50 percent interest in the Atoka natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and two idle natural gas processing plants, all located in Oklahoma. The following table sets forth information with respect to Enogex’s active natural gas processing plants:

				2009 Average Daily		Inlet
Processing	Year		Fuel	Inlet Volumes		Capacity
Plant	Installed	Type of Plant	Capability	(MMcf/d)		(MMcf/d)
Calumet (A)	1969	Lean Oil	Gas/Electric		129		250
Cox City (B)	1994	Cryogenic	Gas/Electric		162		180
Thomas (A)	1981	Cryogenic	Gas		131		135
Clinton (A)(C)	2009	Cryogenic	Electric		22		120
Roger Mills (B)	2008	Refrigeration	Electric		42		100
Canute (B)	1996	Cryogenic	Electric		55		60
Wetumka (A)	1983	Cryogenic	Gas/Electric		47		60
Harrah (A)	1994	Cryogenic	Gas/Electric		13		38
Atoka (D)	2007	Refrigeration	Electric		16		20
Total					617		963

(A)	These processing plants are located on property that Enogex owns in fee.

(B)	These processing plants are located on easements or leased property as described above.

(C)	The Clinton plant was placed in service in late October 2009.

(D)	This processing plant is leased and located on property that Atoka owns in fee.

Enogex occupies 116,184 square feet of office space at its executive offices at 515 Central Park Drive, Suite 110, Oklahoma City, Oklahoma 73105 under a lease that expires March 31, 2012. Although Enogex may require additional office space as its business expands, Enogex believes that its existing facilities are adequate to meet its needs for the immediate future. In addition to its executive offices, Enogex 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, compressor station 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 $2.5 billion and gross retirements were approximately $157.5 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to approximately 29.3 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 Consolidated Financial Statements. Except as set forth below and in Notes 13 and 14 of Notes to Consolidated Financial Statements, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

1. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which 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 Btu 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 all Company parties. The Company now considers this case closed and, as a result, during the third quarter of 2009, the Company reversed a reserve of approximately $1.5 million that was originally established with the 1999 acquisition of Transok.

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

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.

The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

3. Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II). On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case. OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of the Company were named in this case. The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

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.

4. Oklahoma Royalty Lawsuit. On July 22, 2005, Enogex along with certain other unaffiliated co-defendants was served with a purported class action which had been filed on February 7, 2005 by Farris Buser and other named plaintiffs in the District Court of Canadian County, Oklahoma. The plaintiffs own royalty interests in certain oil and gas producing properties and allege they have been under-compensated by the named defendants, including Enogex and its subsidiaries, relating to the sale of liquid hydrocarbons recovered during the transportation of natural gas from the plaintiffs’ wells. The plaintiffs assert breach of contract, implied covenants, obligation, fiduciary duty, unjust enrichment, conspiracy and fraud causes of action and claim actual damages in excess of $10,000, plus attorneys’ fees and costs, and punitive damages in excess of $10,000. Enogex and its subsidiaries filed a motion to dismiss which was granted on November 18, 2005, subject to the plaintiffs’ right to conduct discovery and the possible re-filing of their allegations in the petition against the Enogex companies. On September 19, 2005, the co-defendants, BP America, Inc. and BP America Production Company (collectively, “BP”), filed a cross claim against Products seeking indemnification and/or contribution from Products based upon the 1997 sale of a third-party interest in one of Products natural gas processing plants. On May 17, 2006, the plaintiffs filed an amended petition against Enogex and its subsidiaries. Enogex and its subsidiaries filed a motion to dismiss the amended petition on August 2, 2006. The hearing on the dismissal motion was held on November 20, 2006 and the court denied Enogex’s motion. Enogex companies filed an answer to the amended petition and BP’s cross claim on January 16, 2007. Based on Enogex’s investigation to date, the Company believes these claims and cross claims in this lawsuit are without merit and intends to continue vigorously defending this case.

5. Hull v. Enogex LLC. On November 14, 2008, a natural gas gathering pipeline owned by Enogex ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused injuries to one resident and destroyed three residential structures. The cause of the rupture is not known and an investigation of the incident is ongoing. The damaged pipeline hasbeen repaired and the pipeline is back in service. After the incident, Enogex coordinated and assisted the affected residents. Enogex resolved matters with two of the residents and Enogex continues to seek resolution with a remaining resident. This resident filed a legal action in May 2009 in the District Court of Cleveland County, Oklahoma, against OGE Energy and Enogex seeking to recover actual and punitive damages in excess of $10,000. The parties participated in a mediation of the

pending action in August but were unable to resolve the action. Enogex has requested information regarding property and non-economic damage from the plaintiffs but has not yet received a response. Enogex intends to make full payment for actual medical expenses and property damages in this case. While the Company cannot predict the outcome of this lawsuit at this time, the Company intends to vigorously defend any demand for punitive damages or excessive compensatory damages in this case and believes that its ultimate resolution will not be material to the Company’s consolidated financial position or results of operations.

6. Franchise Fee Lawsuit. On June 19, 2006, two OG&E 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 OG&E’s electric bills. The plaintiffs claim that OG&E 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. OG&E’s motion for summary judgment was denied by the trial judge. OG&E 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 OG&E to collect the challenged franchise fee charges. On March 10, 2009, the Oklahoma Attorney General, OG&E, 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 OG&E 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 OG&E’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 OG&E’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. OG&E believes that the lawsuit is without merit.

7. Oxley Litigation. OG&E 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 OG&E 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, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E 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, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

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

None.

Executive Officers of the Registrant.

The following persons were Executive Officers of the Registrant as of February 18, 2010:

Name

Age

Title

Peter B. Delaney	56	Chairman of the Board, President and Chief Executive Officer
		- OGE Energy Corp. and Chief Executive Officer - Enogex LLC

Danny P. Harris	54	Senior Vice President and Chief Operating Officer - OGE Energy
		Corp. and President - Enogex LLC

Sean Trauschke	42	Vice President and Chief Financial Officer - OGE Energy Corp. and
		Chief Financial Officer - Enogex LLC

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

Gary D. Huneryager	59	Vice President - Internal Audits - OGE Energy Corp.

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

Jesse B. Langston	47	Vice President - Utility Commercial Operations - OG&E

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

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

Stephen E. Merrill	45	Vice President - Human Resources - OGE Energy Corp.

E. Keith Mitchell	47	Senior Vice President and Chief Operating Officer - Enogex LLC

Howard W. Motley	61	Vice President - Regulatory Affairs - OG&E

Reid V. Nuttall	52	Vice President - Chief Information Officer - OGE Energy Corp.

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

Paul L. Renfrow	53	Vice President - Public Affairs - OGE Energy Corp.

John Wendling, Jr.	53	Vice President - Power Supply - OG&E

Max J. Myers	35	Treasurer - OGE Energy Corp.

Scott Forbes	52	Controller and Chief Accounting Officer - OGE Energy Corp.

Jerry A. Peace	47	Chief Risk Officer - OGE Energy Corp.

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 OG&E. Each officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners, 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 Corp. and OG&E
	2005 – Present:	Chief Executive Officer of Enogex LLC
	2007:	President and Chief Operating Officer of OGE Energy Corp.
		and OG&E
	2005 – 2007:	Executive Vice President and Chief Operating Officer of OGE
		Energy Corp. and OG&E
	2005:	President of Enogex Inc.

Danny P. Harris	2007 – Present:	Senior Vice President and Chief Operating Officer of OGE
		Energy Corp. and OG&E and President of Enogex LLC
	2005 – 2007:	Senior Vice President of OGE Energy Corp. 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
		Corp. and OG&E 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 Corp. and OG&E
	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 Corp.

Gary D. Huneryager	2005 – Present:	Vice President – Internal Audits of OGE Energy Corp. and
		OG&E
	2005:	Internal Audit Officer of OGE Energy Corp. and OG&E

S. Craig Johnston	2007 – Present:	Vice President – Strategic Planning and Marketing of OGE
		Energy Corp. and OG&E
	2005 – 2007:	Senior Vice President of Worldwide Oil & Gas Markets of Air
		Liquide (industrial gases company)

Jesse B. Langston	2006 – Present:	Vice President – Utility Commercial Operations of OG&E
	2005 – 2006:	Director – Utility Commercial Operations of OG&E
	2005:	Director – Corporate Planning of OG&E

Jean C. Leger, Jr.	2008 – Present:	Vice President – Utility Operations of OG&E
	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 Corp. and OG&E
	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)

Stephen E. Merrill	2009 – Present:	Vice President – Human Resources of OGE Energy Corp. and OG&E
	2007 – 2009:	Vice President and Chief Financial Officer of Enogex LLC
	2006 – 2007:	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)

Name

Business Experience

E. Keith Mitchell	2007 – Present:	Senior Vice President and Chief Operating Officer of Enogex LLC
	2007:	Senior Vice President of Enogex Inc.
	2005 – 2007:	Vice President – Transportation Services of Enogex Inc.

Howard W. Motley	2006 – Present:	Vice President – Regulatory Affairs of OG&E
	2005 – 2006:	Director – Regulatory Affairs and Strategy of OG&E

Reid V. Nuttall	2009 – Present:	Vice President – Chief Information Officer of OGE Energy Corp.
		and OG&E
	2006 – 2009:	Vice President – Enterprise Information and Performance of
		OGE Energy Corp. and OG&E
	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 OG&E
	2005 – 2007:	Vice President – Transmission of OG&E

Paul L. Renfrow	2005 – Present:	Vice President – Public Affairs of OGE Energy Corp. and OG&E
	2005:	Director – Public Affairs of OGE Energy Corp. and OG&E

John Wendling, Jr.	2007 – Present:	Vice President – Power Supply of OG&E
	2005 – 2007:	Director – Power Plant Operations of OG&E
	2005:	Plant Manager – Sooner Power Plant of OG&E

Max J. Myers	2009 – Present:	Treasurer of OGE Energy Corp. and OG&E
	2008:	Managing Director of Corporate Development and Finance of
		OGE Energy Corp. and OG&E
	2005 – 2008:	Manager of Corporate Development of OGE Energy Corp.
		and OG&E
	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 Corp.
		and OG&E
	2008 – 2009:	Interim Chief Financial Officer of OGE Energy Corp. and OG&E
	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 Corp. and OG&E
	2005 – 2008:	Chief Risk Officer and Compliance Officer of OGE Energy Corp.
		and OG&E

PART II

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

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

	Dividend		Price
2010	Paid		High		Low

First Quarter (through January 31)	$	0.3625	$	37.92	$	35.50

	Dividend		Price
2009	Paid		High		Low

First Quarter	$	0.3550	$	26.80	$	19.70

Second Quarter		0.3550		28.55		23.19

Third Quarter		0.3550		33.72		26.50

Fourth Quarter		0.3550		37.79		31.66

	Dividend		Price
2008	Paid		High		Low

First Quarter	$	0.3475	$	36.23	$	29.83

Second Quarter		0.3475		34.02		30.61

Third Quarter		0.3475		34.74		29.67

Fourth Quarter		0.3475		31.41		19.56

The number of record holders of the Company’s Common Stock at December 31, 2009, was 21,971. The book value of the Company’s Common Stock at December 31, 2009, was $21.06.

Dividend Restrictions

Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of preferred stock of the Company outstanding. Because the Company is a holding company and conducts all of its operations through its subsidiaries, the Company’s cash flow and ability to pay dividends will be dependent on the earnings and cash flows of its subsidiaries and the distribution or other payment of those earnings to the Company in the form of dividends or distributions, or in the form of repayments of loans or advances to it. The Company expects to derive principally all of the funds required by it to enable it to pay dividends on its common stock from dividends paid by OG&E, on OG&E’s common stock, and from distributions paid by Enogex, on Enogex’s limited liability company interests. The Company’s ability to receive dividends on OG&E’s common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding and the covenants of OG&E’s certificate of incorporation and its debt instruments limiting the ability of OG&E to pay dividends. The Company’s ability to receive distributions on Enogex’s limited liability company interests is subject to the prior rights of existing and future holders of such limited liability company interests that may be outstanding and the covenants of Enogex’s debt instruments (including its revolving credit agreement) limiting the ability of Enogex to pay distributions.

Under OG&E’s certificate of incorporation, if any shares of its preferred stock are outstanding, dividends (other than dividends payable in common stock), distributions or acquisitions of OG&E common stock:

may not exceed 50 percent of OG&E’s net income for a prior 12-month period, after deducting dividends on any preferred stock during the period, if the sum of the capital represented by the common stock, premiums on capital stock (restricted to premiums on common stock only by Securities and Exchange Commission orders), and surplus accounts is less than 20 percent of capitalization;

Ÿ	may not exceed 75 percent of OG&E’s net income for such 12-month period, as adjusted if this capitalization ratio is 20 percent or more, but less than 25 percent; and

Ÿ	if this capitalization ratio exceeds 25 percent, dividends, distributions or acquisitions may not reduce the ratio to less than 25 percent except to the extent permitted by the provisions described in the above two bullet points.

OG&E’s certificate of incorporation further provides that no dividend may be declared or paid on the OG&E common stock until all amounts required to be paid or set aside for any sinking fund for the redemption or purchase of OG&E cumulative preferred stock, par value $25 per share, have been paid or set aside. Currently, no shares of OG&E preferred stock are outstanding and no portion of the retained earnings of OG&E is presently restricted by these provisions.

Under Enogex’s current revolving credit agreement, Enogex generally may not make distributions if an event of default exists and otherwise may make monthly and quarterly distributions in amounts not to exceed the amount by which Enogex’s cash on hand exceeds its current and anticipated needs, including, without limitation, for operating expenses, debt service, acquisitions and a reasonable contingency reserve.

Issuer Purchases of Equity Securities

The shares indicated below represent shares of Company common stock purchased on the open market by the trustee for the Company’s 401(k) Plan and reflect shares purchased with employee contributions as well as the portion attributable to the Company’s matching contributions.

						Approximate Dollar
					Total Number of	Value of Shares that
					Shares Purchased as	May Yet Be
	Total Number of		Average Price Paid		Part of Publicly	Purchased Under the
Period	Shares Purchased		per Share		Announced Plan	Plan
1/1/09 – 1/31/09		81,300	$	25.33	N/A	N/A
2/1/09 – 2/28/09		145,200	$