(Mark One)

x  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

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

 

                           Commission File Number: 1-12579

 

 

 

 

 

---

 

 

OGE ENERGY CORP.

 

FORM 10-K

 

FOR THE YEAR ENDED DECEMBER 31, 2007

 

TABLE OF CONTENTS

 

 

 

i

 

---

 

 

FORWARD-LOOKING STATEMENTS

 

Except for the historical statements contained herein, the matters discussed in this Annual Report on 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,” factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

 

 

1

 

---

PART I

 

Item 1. Business.

 

THE COMPANY

 

Introduction

 

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 15 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 regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

 

Enogex Inc. and its subsidiaries (“Enogex”) are a provider of integrated natural gas midstream services. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing. Historically, Enogex had also engaged in natural gas marketing through its subsidiary, OGE Energy Resources, Inc. (“OERI”). In connection with the proposed initial public offering of common units of the Partnership discussed below, on January 1, 2008, Enogex distributed the stock of OERI to OGE Energy.

 

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

 

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

 

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

 

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

 

2

 

---

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

 

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

 

 

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

 

Enogex plans to continue to implement improvements to enhance long-term financial performance of its mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects and increased utilization of existing assets and strategic acquisitions. In addition, Enogex is seeking to diversify its gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with the Company’s strategic capabilities. Over the past several years, Enogex has initiated multiple organic growth projects. Currently, Enogex’s organic growth capital expenditures are focused on three primary areas:

 

 

3

 

---

ELECTRIC OPERATIONS - OG&E

 

General

 

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. During 2007, five 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 88 percent of its total electric operating revenues for the year ended December 31, 2007 from sales in Oklahoma and the remainder from sales in Arkansas.

 

OG&E’s system control area peak demand as reported by the system dispatcher during 2007 was approximately 6,317 MWs on August 14, 2007. OG&E’s load responsibility peak demand was approximately 6,031 MWs on August 14, 2007. As reflected in the table below and in the operating statistics that follow, there were approximately 26.4 million megawatt-hour (“MWH”) sales to OG&E’s customers (“system sales”) in both 2007 and 2006 and 26.0 million MWH system sales in 2005. Variations in system sales for the three years are reflected in the following table:

 

 

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. See Note 17 of Notes to Consolidated Financial Statements for a discussion of the potential impact on competition from federal and state legislation.

 

4

 

---

 

 

5

 

---

Regulation and Rates

 

OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of OG&E’s facilities and operations. For the year ended December 31, 2007, approximately 87 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and four percent to the FERC.

 

The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

 

OG&E has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by OG&E due to the significant problems faced by other states in their electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail in Note 17 of Notes to Consolidated Financial Statements.

 

Recent Regulatory Matters

 

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

 

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

 

See Note 17 of Notes to Consolidated Financial Statements for a discussion of certain regulatory matters including, among other things, security enhancements, review of OG&E’s fuel adjustment clause, cogeneration credit rider, OG&E FERC audit, national energy legislation and state legislative initiatives.

 

Regulatory Assets and Liabilities

 

OG&E, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71. SFAS No. 71 provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that

 

6

 

---

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, 2007 and 2006, OG&E had regulatory assets of approximately $330.7 million and $319.2 million, respectively, and regulatory liabilities of approximately $148.2 million and $224.5 million, respectively. See Note 1 of Notes to Consolidated Financial Statements for a further discussion.

 

As discussed in Note 17 of Notes to Consolidated Financial Statements, legislation was enacted in the 1990’s for Oklahoma that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented, this legislation could deregulate OG&E’s electric generation assets and cause OG&E to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect OG&E’s electric transmission and distribution assets and OG&E believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

 

Rate Structures

 

Oklahoma

 

OG&E’s standard tariff rates include a cost-of-service component (including an authorized return on capital) plus an automatic 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. The GFB option received OCC approval for permanent rate status in OG&E’s rate case completed in December 2005. 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. A third rate offering available to commercial and industrial customers is levelized demand billing. This program is beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. Another program being offered to OG&E’s commercial and industrial customers is a voluntary load curtailment program. This program provides customers with the opportunity to curtail 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.

 

The previously discussed rate options, coupled with OG&E’s other rate choices, provide many tariff options for OG&E’s Oklahoma retail customers. OG&E’s rate choices, reduction in cogeneration rates, acquisition of additional generation resources and overall low costs of production and deliverability are expected to provide valuable benefits for our customers for many years to come. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices.  There was no overall material impact in 2006 associated with these rate options; however, there was an increase in other income from the GFB option in 2007. Revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose alternative rate options.

 

As part of the rate order issued by the OCC in December 2005, OG&E received OCC approval for the creation of two new rate classes, Public Schools-Demand and Public Schools Non-Demand. These two classes of service will provide OG&E flexibility to provide targeted programs for load management to public schools and their unique usage patterns. Another item approved in the order was the creation of service level fuel differentiation that allows customers to pay fuel

 

7

 

---

costs that better reflect operational energy losses related to a specific service level. The OCC order also approved a military base rider that demonstrates Oklahoma’s continued commitment to our military partners.

 

Arkansas

 

During 2006, energy efficiency hearings were held by the APSC for all Arkansas utilities. These hearings led to new rules being approved for all Arkansas utilities in January 2007. OG&E filed for seven new energy efficiency programs that were accepted and approved by the APSC in September 2007. Six of the seven programs were implemented in October 2007 and have attracted new customers, which management believes has resulted in an improved use of energy resources throughout OG&E’s Arkansas jurisdiction. The revised compact fluorescent lamp and energy efficiency program is expected to be submitted in March 2008 seeking approval for immediate implementation in 2008.

 

Fuel Supply and Generation

 

During 2007, approximately 62 percent of the OG&E-generated energy was produced by coal-fired units, 36 percent by natural gas-fired units and two percent by wind-powered units. Of OG&E’s 6,229 total MW capability reflected in the table under Item 2. Properties, approximately 3,514 MWs, or 56 percent, are from natural gas generation, approximately 2,595 MWs, or 42 percent, are from coal generation and approximately 120 MWs, or two 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. A slight decline in the percentage of coal generation in future years is expected to result from increased usage of natural gas generation and/or wind generation required to meet growing energy needs. Over the last five years, the weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

 

 

The increase in the weighted average cost of fuel in 2007 as compared to 2006 was primarily due to increased natural gas volumes. The decrease in the weighted average cost of fuel in 2006 as compared to 2005 was primarily due to decreased natural gas prices partially offset by increased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2005 and in 2004 was primarily due to increased natural gas prices and increased amounts of natural gas being burned. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of these fuel costs that is not included in the base rates is recoverable through OG&E’s automatic fuel adjustment clauses that are approved by the OCC and the APSC.

 

Coal

 

All of OG&E’s coal-fired units, with an aggregate capability of approximately 2,595 MWs, are designed to burn low sulfur western coal. OG&E purchases coal primarily under contracts expiring in years 2010 and 2011. During 2007, OG&E purchased approximately 9.6 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.3 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.20 lbs. of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E’s coal units have an approximate emission rate of 0.51 lbs. of sulfur dioxide per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 16 of Notes to Consolidated Financial Statements.

 

OG&E has continued its efforts to maximize the utilization of its coal-fired units at its Sooner and Muskogee generating plants. See “Environmental Laws and Regulations” in Note 16 of Notes to Consolidated Financial Statements for a discussion of environmental matters which may affect OG&E in the future.

 

Coal Shipment Disruption

 

In mid-2005, OG&E experienced a coal shipment disruption due to successive derailments on the jointly-owned rail line serving the Southern Powder River Basin coal producers. As a result, OG&E’s level of coal inventory significantly decreased. In late 2005, the rail lines were repaired and returned to normal operating conditions. At December 31, 2007, OG&E had slightly more than 57 days of coal supply for each of its coal-fired units at its Sooner and Muskogee generating plants. Furthermore, if no other significant disruptions occur going forward, OG&E expects to maintain its coal inventory level at approximately 60 days.

 

8

 

---

Natural Gas

 

In August 2007, OG&E issued an RFP for gas supply purchases for periods from November 2007 through March 2008, which accounted for approximately 15 percent of its projected 2008 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices and will expire in 2008. Additional gas supplies to fulfill OG&E’s remaining 2008 natural gas requirements will be acquired through additional RFPs in early to mid-2008, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.

 

In 1993, OG&E began utilizing a natural gas storage facility for storage services that allowed OG&E to maximize the value of its generation assets. Storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with OG&E. At December 31, 2007, OG&E had approximately 2.0 million MMBtu’s in natural gas storage that it acquired for approximately $8.6 million.

 

Purchased Power

 

In March 2007, OG&E issued an RFP for capacity and/or firm energy purchases for the summer periods of 2008, 2009, and/or 2010. In November 2007, OG&E signed a purchase contract with Redbud for purchases in the summer periods of 2008 and 2009. OG&E submitted notice of the contract to the OCC on January 2 and 3, 2008. Interventions and protests were due within 15 days of submission of the notice. No interventions or protests were received in this matter and OG&E considers this purchase contract to be final. The purchase contract will be terminated if the acquisition of Redbud by OG&E, the OMPA and the GRDA is completed as discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Wind

 

In January 2007, OG&E’s 120 MW Centennial wind farm was fully in service. The OCC authorized a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. As indicated in the settlement agreement with the OCC related to OG&E’s Centennial wind farm, OG&E must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009. Also, during 2003, OG&E entered into a 15-year contract with FPL Energy whereby OG&E has access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma.

 

On October 30, 2007, OG&E announced its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, OG&E expects to issue an RFP in the first quarter of 2008. OG&E also announced its desire to begin building a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle. This high-capacity transmission line would be used by OG&E and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states. The increase in wind power generation would be subject to numerous regulatory and other approvals, including proposed regulatory treatment from the OCC.

 

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 OG&E 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. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the

 

9

 

---

Texas Panhandle. Enogex’s ongoing operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing.

 

Historically, Enogex had also engaged in natural gas marketing through its subsidiary, OERI. In connection with the proposed Offering of the Partnership, on January 1, 2008, Enogex distributed the stock of OERI to OGE Energy.

 

Transportation and Storage

 

General

 

Enogex’s transportation and storage business owns and operates approximately 2,318 miles of intrastate natural gas transportation pipelines with approximately 1.52 trillion British thermal units per day (“TBtu/d”) of average daily throughput during 2007. Enogex also owns and operates two storage facilities currently being operated at a working gas level of approximately 23 billion cubic feet (“Bcf”). Enogex provides fee-based intrastate transportation services on a firm and interruptible basis and, pursuant to Section 311 of the Natural Gas Policy Act (“NGPA”), provides interstate transportation services on an interruptible 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 cases, 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 only obligated to transport natural gas nominated by the shipper 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. To the extent pipeline capacity is not needed for such firm intrastate transportation service, 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 in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma). At December 31, 2007, Enogex was connected to 11 third-party natural gas pipelines at 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, Enbridge Pipelines and Ozark Gas Transmission, L.L.C. Further, Enogex is connected to 27 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma.

 

Enogex owns and operates two 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 23 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 to third parties. 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 negotiated with each customer. Enogex’s storage facilities are also used to support its no-notice load following transportation and storage contract with OG&E.

 

Enogex uses its storage assets to meet its contractual obligations under certain load following transportation contracts. Enogex also periodically conducts an open season to solicit commitments for contracted capacity and deliverability to third parties for contracts that generally do not exceed three years.

 

Customers and Contracts

 

Enogex’s major transportation customers are OG&E and 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, which expires January 1, 2013, unless extended, and the OG&E contract, which expires April 30, 2009, unless extended, provide for a monthly demand charge plus variable transportation charges (including fuel). 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. Natural gas produced in excess of that which is used during the winter months is typically stored to meet the increased demand for natural gas during the summer months. During 2005, 2006 and 2007, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $95.0 million, $98.1 million and $103.9 million,

 

10

 

---

respectively, of which approximately $47.6 million, $47.6 million and $47.4 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $13.3 million, respectively, was attributed to PSO. Revenues from Enogex’s firm intrastate transportation and storage contracts represented approximately 38 percent of Enogex’s consolidated gross margin in 2005, 31 percent in 2006 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 the FERC Staff panel and an administrative appellate review. In the past, Enogex has successfully settled, rather than litigated, its Section 311 rate cases. Offering interruptible Section 311 transportation gives Enogex the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase its transportation revenues without increasing its regulatory burden appreciably. Enogex currently has two zones under its Section 311 rate structure - an East Zone and a West Zone with a maximum transportation rate and a fuel retention rate for each zone. Enogex may charge up to its maximum established zonal East and West transportation rates for transportation in one zone or cumulative maximum rates for transportation in both zones and the applicable fixed zonal fuel percentage(s) for the fuel used in shipping natural gas under Section 311 on the Enogex system.

 

The fixed zonal fuel percentages are adjusted annually and remain in effect for a calendar year. The mechanism used to establish the percentages is a fuel tracker filed annually at the FERC to establish prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year. Fuel usage is later trued-up to actual usage over a two-year period based on the value of the gas at the time of usage.

 

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for service in the East Zone and West Zone. Enogex’s filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some additionally filed protests. In the normal course of the triennial rate case, the FERC Staff and intervenors serve data requests on Enogex with respect to the cost of service submitted with the filing in support of the proposed rates and the parties, thereafter, undertake settlement discussions. There is no statutory deadline by which the FERC must act on the filing. The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action, as the FERC has done in past Enogex cases. The FERC Staff has served its initial data requests on Enogex and Enogex has submitted its responses. The parties are currently in settlement negotiations. The FERC Staff, Enogex and one intervenor have exchanged offers of settlement, but a settlement has not been reached. Enogex has not, as of yet, placed the increased rates into effect. Enogex must file its next rate case no later than October 1, 2010 to comply with the FERC’s requirement for triennial filings.

 

On November 15, 2007, Enogex made its annual filing to establish fixed fuel percentages for its East Zone and West Zone, respectively, for calendar year 2008 (“2008 Fuel Year”). There were no protests and the FERC accepted the proposed zonal fuel percentages for 2008 Fuel Year by order of December 19, 2007.

 

11

 

---

On May 29, 2007, the FERC notified Enogex that it was commencing an audit to determine whether and how Enogex is complying with periodic regulatory reporting requirements for intrastate pipelines. On the same day, the FERC notified a number of other intrastate pipelines and storage entities of comparable audits. In preparing for the audit, Enogex advised the FERC Staff that it had inadvertently failed to timely file three storage reports required under FERC regulations. Enogex promptly submitted those storage reports to the FERC. The FERC completed its audit of Enogex in September 2007 and approved the corrective actions taken by Enogex and determined that no further corrective action is required.

 

Enogex received FERC approval to unbundle its remaining gathering assets and services from its transportation services and completed such unbundling, effective October 1, 2005. As a result, FERC regulates Enogex’s Section 311 transportation services but does not regulate its gathering services. In addition, the FERC does not regulate Enogex’s intrastate transportation services because these services are not Section 311 services. These services include those intrastate transportation services provided to the gas-fired electric generation facilities and other end users within Oklahoma. As such the rates charged by Enogex for transporting natural gas for the Oklahoma utility companies, independent electric generation facilities and other shippers within Oklahoma are not subject to FERC regulation. Nor are the rates charged by Enogex for any intrastate transportation service subject to direct state regulation by the OCC. However, 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.

 

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 has adopted regulations requiring pipeline operators to develop integrity management programs for its transportation pipelines. During 2007, Enogex incurred approximately $11.7 million of capital expenditures and operating costs to implement its pipeline integrity management program along certain segments of its natural gas pipelines. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $31.9 million between 2008 and 2011 in connection with its pipeline integrity management program. 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 as a result of the integrity management program. At this time, Enogex cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. Enogex will continue its pipeline integrity program 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. Currently, in Enogex’s transportation and storage business, organic growth capital expenditures are focused on upgrades to Enogex’s existing transportation system due to increased volumes as a result of the broader shift of gas flow from the Rocky Mountains and the mid-continent to markets in the northeast and southeast United States.

 

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

 

MEP filed an application with the FERC on October 9, 2007 requesting a certificate of public convenience and necessity authorizing MEP to construct its pipeline and lease certain capacity from Enogex. On October 9, 2007, Enogex also filed an application with the FERC for issuance of a limited jurisdiction certificate authorizing its lease agreement with MEP. Certain Enogex shippers have filed motions to intervene in Enogex’s FERC certificate proceeding, and some have protested Enogex’s certificate application. Protestors have claimed that it is unduly discriminatory for Enogex to propose to lease capacity to MEP while not generally offering firm interstate transportation service, that the lease arrangement will adversely affect the availability of interruptible interstate transportation service on the Enogex system and that the lease payment

 

12

 

---

specified under the MEP lease agreement is unduly preferential in MEP’s favor. These protestors have urged the FERC to reject the MEP lease arrangement or to condition its acceptance on a requirement that Enogex offer existing shippers taking interruptible interstate service the opportunity to convert that service to firm service. One protestor has asked the FERC to consolidate the Enogex certificate proceeding with Enogex’s Section 311 triennial rate proceeding currently pending before the FERC. While Enogex cannot predict what action the FERC may take regarding the lease agreement, Enogex believes that the proposed MEP lease arrangement is consistent with FERC policy and precedent involving similar lease arrangements.

 

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

 

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 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. Furthermore, the processing plants produce marketable NGLs.

 

Enogex’s gathering system includes approximately 5,534 miles of natural gas gathering pipelines with approximately 1.05 TBtu/d of average daily throughput during 2007 extending from southwestern Oklahoma to the eastern Texas Panhandle. During 2007, Enogex connected 374 new producing wells (including 196 wells behind central receipt points), located in the Arkoma and Anadarko basins (including recent growth activity in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma) to its gathering systems. At December 31, 2007, Enogex’s gathering system was connected to approximately 3,100 wells and approximately 250 central receipt points, all of which are equipped with state-of-the-art electronic flow measurement technology. Approximately 70 percent of Enogex’s gathered volumes are received at wellheads while 30 percent is gathered from central receipt or other interconnection points.

 

Enogex owns and operates six natural gas processing plants with a total inlet capacity of approximately 723 MMcf/d and has a 50 percent interest in and operates an additional natural gas processing plant with an inlet capacity of approximately 20 MMcf/d, 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 of the seven processing plants operated 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, 2007, Enogex extracted and sold approximately 385 million gallons of NGLs.

 

In 2007 and 2008, Enogex has pursued and expects to pursue several projects to address tightening processing capacity as a result of increasing supply:

 

 

 

13

 

---

 

 

Enogex’s gathering and processing business has approximately 225,000 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” arrangements, “percent-of-proceeds” and “percent-of-liquids” arrangements and “keep-whole” arrangements. Under fee-based arrangements, Enogex earns cash fees for the services that it renders. Under the latter types of arrangements, Enogex generally purchases raw natural gas and sells processed natural gas and NGLs or receives NGLs.   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 NGL prices. Enogex seeks to minimize 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.

 

In addition, as a seller of NGLs, Enogex is exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, in 2002, Enogex revised its SOC used as part of its typical natural gas processing arrangements and included language that requires 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 minimum

 

14

 

---

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.

 

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.

 

Approximately 16 percent of the commercial grade propane produced at Enogex’s 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 and 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 Calumet plant, 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.

 

Several of Enogex’s processing plants are currently operating at or near full capacity, such as the Cox City processing plant. 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.

 

Natural Gas Supply

 

As of December 31, 2007, approximately 3,100 wells and approximately 250 central receipt points were connected to Enogex’s system in Oklahoma and the Texas Panhandle area, areas that have experienced an increase in drilling activity and production. Enogex has secured significant areas of dedication from numerous customers active throughout Enogex’s areas of operations.

 

Customers and Contracts

 

Residue gas remaining after processing is primarily taken in kind by the producer customers into Enogex’s transportation pipelines for redelivery either (a) to on-system customers such as the electric generation facilities of OG&E and PSO, or (b) into downstream interstate pipelines. Enogex’s NGLs are typically sold to NGL marketers, 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., Apache Corporation, Scissortail Energy, LLC, Devon Gas Services, L.P. and Samson Resources Company. During 2007, these five customers accounted for approximately 19 percent, 16 percent, eight percent, five percent and four percent, respectively, of Enogex’s gathering and processing volumes. During 2007, Enogex’s top ten natural gas producer customers accounted for approximately 66 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, LP, 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

 

15

 

---

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. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (the “Competition Bill”) and H.B. 1920 (the “Lost and Unaccounted for Gas (“LUG”) Bill”). The Texas Competition Bill and LUG Bill contain provisions applicable to various natural gas industry participants, including gatherers. The Competition Bill allows the Railroad Commission of Texas (“TRRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings, if a complaint is filed and a determination is made that such a rate is necessary to remedy unreasonable discrimination. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to impose administrative penalties against purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It expands the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders for purposes of preventing waste in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. Enogex cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on its gathering operations.

 

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 also may be subject to additional safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management 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 through the construction of new facilities and expansion of existing facilities and the interest in the joint venture, Atoka Midstream LLC, and expansions on the west side of Enogex’s gathering system, primarily in the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle.

 

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

 

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

 

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

 

16

 

---

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

 

Technology Improvements

 

Enogex continues to upgrade its data and information systems in order to improve operational efficiencies and increase profitability of its business and that of its customers.

 

 

 

 

 

 

Safety and Health Regulation

 

Enogex is subject to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within 10 years. The U.S. Department of Transportation (“DOT”) has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

 

A four-mile portion of Enogex’s pipeline is also subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996 (the “Hazardous Liquid Pipeline Safety Act”) and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of liquid pipeline facilities. The Hazardous Liquid Pipeline Safety Act covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. Enogex believes that it is in material compliance with these Hazardous Liquid Pipeline Safety Act regulations.

 

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 anticipates that it should be able to comply with currently existing state laws and regulations applicable to pipeline safety without incurring material costs. Enogex’s natural gas pipelines have inspection and compliance programs designed to maintain compliance with pipeline safety and pollution control requirements.

 

17

 

---

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

 

As discussed above, in connection with the proposed initial public offering of common units of the Partnership, Enogex distributed the stock of OERI to OGE Energy. Enogex has historically utilized, and is expected to continue to utilize, OERI for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2005, 2006 and 2007, OERI recorded revenues from Enogex of approximately $160.6 million, $107.1 million and $95.2 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2005, 2006 and 2007, Enogex recorded revenues from OERI of approximately $330.5 million, $291.9 million and $304.3 million, respectively, for the sale, at market rates, of natural gas. Enogex has paid, and is expected to continue to pay, certain fees to OERI for providing natural gas marketing, hedging, risk management and other related services.

 

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 dropped from approximately 0.8 Bcf in 2006 to approximately 0.7 Bcf in 2007.  This reflects selective deal execution to assure adequate margin in light of credit and other risks in the current high commodity price environment. OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by OERI by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the over-the-counter market, subject to daily and monthly trading stop loss limits of $2.5 million and daily value-at-risk limits of $1.5 million in accordance with corporate policies.              

 

Competition

 

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

 

For the year ended December 31, 2007, approximately 56.1 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers, of which approximately 11.9 percent was with affiliates of OERI. The remaining 43.9 percent of service volumes were to marketers, municipals, cooperatives and industrials. At December 31, 2007, approximately 78.6 percent of the payment exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services (“Standard & Poor’s”) and approximately 1.6 percent having less than investment

 

18

 

---

grade ratings. The remaining 19.8 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, with regard to OERI’s physical purchases and sales of these energy commodities, and any related hedging activities that it undertakes, 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 as well as 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

 

OG&E and Enogex believe that their operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on their business, consolidated financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, 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 $36.9 million of the Company’s capital expenditures budgeted for 2008 are to comply with environmental laws and regulations, of which approximately $36.0 million and $0.9 million are related to OG&E and Enogex, respectively. Approximately $121.4 million of the Company’s capital expenditures budgeted for 2009 are to comply with environmental laws and regulations, of which approximately $120.5 million and $0.9 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 to preserve and enhance environmental quality will be approximately $94.7 million and $4.5 million, respectively, during 2008 as compared to approximately $63.5 million and $4.9 million, respectively, during 2007. 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 Note 16 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

 

19

 

---

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.

 

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 joint and several, strict liability for the costs of cleaning up and restoring sites where those substances have been released to the environment, for damages to natural resources and for costs of certain health studies. 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, compression and processing of natural gas. 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, 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. OG&E and Enogex believe, however, that their operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to OG&E and Enogex than to any other similarly situated companies. See Note 16 of Notes to Consolidated Financial Statements for a discussion of environmental capital expenditures related to air emissions.

 

Water Discharges

 

OG&E’s and Enogex’s operations are subject to the Federal Water Pollution Control Act of 1972, as amended (“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

 

20

 

---

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.

 

Other Laws and Regulations

 

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

 

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 primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage, delays in recovering unconditional fuel purchase obligations and fuel clause under and over recoveries. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

 

Capital Expenditures

 

The Company’s current 2008 to 2013 construction program includes continued investment in OG&E’s distribution, generation and transmission system and Enogex’s pipeline assets. The Company’s current estimates of capital expenditures are approximately: 2008 - $1.1 billion (approximately $434.5 million are related to the proposed acquisition of the Redbud power plant), 2009 - $613.9 million, 2010 - $668.1 million, 2011 - $653.4 million, 2012 - $670.8 million and 2013 - $654.1 million. OG&E also has approximately 430 MWs of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.

 

On October 30, 2007, OG&E announced its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, OG&E expects to issue an RFP in the first quarter of 2008. OG&E also announced its desire to begin building a high-capacity transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle that would be used by OG&E and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states. OG&E has also previously committed to the SPP to build the Oklahoma portion of the western half of the SPP “X-Plan”. The western half of the X-Plan includes transmission lines from Woodward to Tuco, Texas and from Woodward to Spearville, Kansas. The increase in wind power generation and the

 

21

 

---

building of the transmission lines would be subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP.

 

Pension and Postretirement Benefit Plans

 

During 2007 and 2006, the Company made contributions to its pension plan of approximately $50.0 million and $90.0 million, respectively, to help ensure that the pension plan maintains an adequate funded status. During 2008, the Company may contribute up to $50.0 million to its pension plan. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s pension and postretirement benefit plans.

 

Future Sources of Financing

 

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

 

Issuance of New Long-Term Debt

 

In January 2008, OG&E issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings.

 

Short-Term Debt

 

Short-term borrowings generally are used to meet working capital requirements. At December 31, 2007, the Company had approximately $295.0 million in outstanding commercial paper borrowings. Also, OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2007 and ending December 31, 2008.

 

In December 2006, the Company and OG&E amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for the Company and $400 million for OG&E. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods. In November 2007, the Company and OG&E utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at the end of the two renewal options to convert the outstanding balance to a one-year term loan. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

 

It is currently expected that Enogex will enter into a $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes during the first quarter of 2008.

 

EMPLOYEES

 

 

ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS

 

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

 

Item 1A. Risk Factors.

 

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms “OGE Energy”, “we”, “our” and “us” refer to OGE Energy Corp., “OG&E” refers to our subsidiary Oklahoma Gas and Electric Company and “Enogex” refers to our subsidiary Enogex Inc. and its subsidiaries. In addition to the other information in this Annual Report on Form 10-K and other documents filed by us and/or our subsidiaries with the

 

22

 

---

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. As indicated in the settlement agreement with the OCC related to OG&E’s Centennial wind farm, OG&E must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009. Also, during 2007, OG&E incurred storm-related expenses of approximately $35.9 million for which OG&E intends to seek recovery from its customers in its next rate case.

 

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 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 regulation by the OCC and the APSC, in addition to the FERC. Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate may harm our financial position and results of operations.

 

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

 

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

 

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

 

23

 

---

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

 

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases.  However, government officials in these states have declared support for state and federal action on climate change issues.  OG&E reports 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.  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. See Note 16 of Notes to Consolidated Financial Statements for a further discussion.

 

We have incurred costs in connection with the Red Rock power plant project that has been terminated and we may not be able to fully recover those costs.

 

On September 10, 2007, the OCC denied OG&E and PSO’s request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result of the denial for pre-approval, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. OG&E filed an application with the OCC in December 2007 requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. If the request for deferral is not approved, the deferred costs will be expensed.

 

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 consolidated 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 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, financial

 

24

 

---

position and cash flows. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to constructing new pipelines. 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 regional transmission organization (“RTO”) and has transferred operational authority (but not ownership) of OG&E’s transmission facilities to the SPP RTO. The SPP RTO 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 an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our consolidated financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows.

 

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 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 you 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 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. Enogex is currently charging rates for its Section 311 transportation services that were deemed fair and equitable under a rate settlement approved by the FERC for the period from January 1, 2005 until December 31, 2007. On October 1, 2007, Enogex made its required triennial filing for rates and in its filings proposed the new rates to be effective January 1, 2008. A number of interventions have been filed in response to Enogex’s triennial filings and some of the intervening parties also filed protests. Enogex has not been able to reach a resolution of the issues with the protesting parties but expects to continue to have discussions with customers and to participate in settlement discussions with the FERC Staff and other interested parties. Enogex has not yet placed the higher

 

25

 

---

proposed rates into effect. Enogex cannot predict what the settlement terms will be or, if not settled, what determinations the FERC will make with respect to this proceeding or what impact, if any, those determinations might have on Enogex’s ability to establish transportation rates that would allow Enogex to recover the full cost, including a reasonable return, of operating its transportation facilities and that portion of its storage capacity used in support of transportation services. Accordingly, Enogex cannot predict what impact, if any, such determinations could have on its consolidated financial position, results of operations or cash flows.

 

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 also may be or become subject to safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management 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 transportation pipelines. The regulations require operators to:

 

 

During 2007, Enogex incurred approximately $11.7 million of capital expenditures and operating costs to implement its pipeline integrity management program along certain segments of its natural gas pipelines. Enogex currently estimates that it will incur capital expenditures and operating costs of approximately $31.9 million between 2008 and 2011 in connection with its pipeline integrity management program. 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 as a result of the integrity management program. At this time, we cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. Enogex will continue its pipeline integrity program 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, 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

 

26

 

---

and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.

 

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

 

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

 

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with 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. The Company is subject to a NERC readiness evaluation and compliance audit every three years and cannot predict the outcome of those audits.

 

OPERATIONAL RISKS

 

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

 

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

 

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

 

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

 

27

 

---

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 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. During 2007, OG&E incurred storm-related expenses of approximately $35.9 million for which OG&E intends to seek recovery from the its customers in its next rate case.

 

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

 

Enogex is subject to risks due to frequent and often substantial fluctuations in commodity prices. Enogex’s results of operations and cash flows could be adversely affected by volatility in natural gas and NGL prices. Enogex’s gathering and processing margins generally improve when NGL prices are high relative to the price of natural gas. In the past, the prices of natural gas and NGLs have been extremely volatile, and Enogex expects this volatility to continue. With respect to natural gas, the mid-continent prices for natural gas, as represented by the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract in 2006 ranged from a high of $8.76 per MMBtu to a low of $3.54 per MMBtu. In 2007, the same index ranged from a high of $6.82 per MMBtu to a low of $4.73 per MMBtu. Natural gas prices reached relatively high levels in late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. With respect to NGLs, the mid-continent prices for propane, for example, as represented by the average of the Oil Price Information Service daily average posting at the Conway, Kansas market, in 2006 ranged from a high of $1.14 per gallon to a low of $0.90 per gallon. In 2007, the same index ranged from a high of $1.52 per gallon to a low of $0.87 per gallon. Enogex’s future revenue and cash flows may be materially adversely affected if the midstream industry experiences significant, prolonged deterioration below general price levels experienced in recent years.

 

Some factors that affect prices of natural gas and NGLs are beyond our control and changes in these prices could adversely affect Enogex’s revenue and cash flows.

 

The markets and prices for natural gas and NGLs depend upon factors beyond Enogex’s control and changes in these prices could adversely affect Enogex’s revenue and cash flows. 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.

 

28

 

---

Enogex’s “keep-whole” natural gas processing arrangements and “percent-of-proceeds” and “percent-of-liquids” natural gas processing agreements expose it to risks associated with fluctuations associated with the price of natural gas and NGLs, which could adversely affect Enogex’s revenue and cash flows.

 

Enogex’s keep-whole natural gas processing arrangements, which constituted approximately 20 percent of its gross margin and accounted for approximately 68 percent of its natural gas processed volumes during 2007, expose it to fluctuations in the pricing spreads between NGL 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 NGL 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 six percent of its gross margin and accounted for approximately 25 percent of its natural gas processed volumes during 2007. 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 our and 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 late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. 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, 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.

 

29

 

---

Enogex 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.

 

Enogex is exposed to changes in commodity prices in its operations. To minimize the risk of commodity prices, Enogex may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas. However, financial derivative contracts do not eliminate the risk of market supply shortages, which could result in Enogex’s inability to fulfill contractual obligations and incurrence of significantly higher energy or fuel costs relative to corresponding sales contracts. Enogex marks its energy trading portfolio to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. When available, market prices are utilized in determining the value of natural gas and related derivative commodity instruments. For longer-term positions, which are limited to a maximum of 60 months, and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

 

Enogex engages in cash flow hedge transactions to manage commodity risk. Hedges of anticipated transactions are documented as cash flow hedges pursuant to Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and are executed based upon management-established price targets. Enogex utilizes hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and storage natural gas, percent-of-liquids and keep-whole natural gas, NGL hedges and certain transportation hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

 

As a result of the factors discussed above, Enogex’s hedging activities may not be as effective as intended in reducing the volatility of its cash flows. In addition, 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 properly followed or do not work as planned. The steps taken to monitor Enogex’s hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

 

Enogex’s results of operations and cash flows may be adversely affected by risks associated with its hedging activities.

 

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. Enogex intends to hedge approximately 70 percent of its NGL volumes when market conditions dictate. As of December 31, 2007, Enogex had hedged approximately 63 percent of its expected non-ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008, 2009 and 2010. As of December 31, 2007, Enogex had hedged approximately 41 percent of its expected ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008. Enogex has the option to reject ethane if processing it is not economical. For periods after 2010, management will 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 NGL 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 will 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.

 

30

 

---

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 NGL supply. During 2007, Chesapeake Energy Marketing Inc., Apache Corporation, Scissortail Energy, LLC, Devon Gas Services, L.P. and Samson Resources Company accounted for approximately 52 percent of Enogex’s natural gas and NGL supply. The loss of the natural gas and NGL 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 has been providing natural gas storage services to OG&E since August 2002 when it acquired the Stuart Storage Facility. 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. During 2005, 2006 and 2007, revenues from Enogex’s firm intrastate transportation and storage contracts were approximately $95.0 million, $98.1 million and $103.9 million, respectively, of which $47.6 million, $47.6 million and $47.4 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $13.3 million, respectively, was attributed to PSO. Enogex’s current contract with OG&E expires in April 2009. OG&E has indicated to Enogex that it currently intends to consider competitive bids for gas transportation and storage services prior to the termination of Enogex’s current agreement with OG&E, but it is not obligated to do so. Enogex’s current contract with PSO expires in January 2013. Even though OG&E is a subsidiary of the Company, there can be no assurance that the current contract with OG&E will be extended or replaced on similar terms or at all. 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.

 

Enogex may not be successful in balancing its purchases and sales of natural gas and NGLs, which would increase its exposure to commodity price risk.

 

In the normal course of business, Enogex purchases or retains from producers and other customers some of the natural gas and NGLs that flow through its natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. Enogex may not be successful in balancing its purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause Enogex’s purchases and sales to be unbalanced. If Enogex’s purchases and sales are unbalanced, it will face increased exposure to commodity price risk and Enogex could have increased volatility in its operating income and cash flows.

 

If third-party pipelines and other facilities interconnected to Enogex’s gathering 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

 

31

 

---

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:

 

 

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 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

 

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

 

We have defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2007, 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.

 

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

 

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

 

32

 

---

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 32 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, 2007, we had outstanding indebtedness and other liabilities of approximately $3.6 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

 

33

 

---

major market disruption as experienced with the market turmoil in August 2007. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit. Also, any downgrade below investment grade at OERI could require us to issue guarantees to support some of OERI’s marketing operations.

 

Any negative change in OERI’s creditworthiness could adversely affect Enogex’s ability to engage in hedging transactions or adversely affect the prices and terms upon which hedging transactions occur.

 

Enogex historically has conducted its hedging activities with OERI as its counterparty. OERI, in turn, has engaged in back-to-back hedging transactions with third parties. The willingness of those third parties to serve as counterparties on OERI’s hedging transactions depends on OERI’s creditworthiness. Any negative change in OERI’s creditworthiness could adversely affect OERI’s and Enogex’s ability to enter into hedging transactions, or the prices and terms upon which such transactions may be effected.

 

Enogex’s debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities.

 

Enogex expects to enter into a $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes during the first quarter of 2008. The new credit facility is expected to include an accordion feature that would allow Enogex to seek an additional $250 million of lending commitments. Following the Offering, Enogex will continue to have the ability to incur additional debt, subject to limitations in its credit facility. The levels of Enogex’s debt could have important consequences, including the following:

 

 

Enogex’s ability to service its debt will depend upon, among other things, Enogex’s future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond Enogex’s control. If operating results are not sufficient to service its current or future indebtedness, Enogex may be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.

 

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.

 

 

34

 

---

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 nine generating stations with an aggregate capability of approximately 6,229 MWs at December 31, 2007. The following table sets forth information with respect to OG&E’s electric generating facilities, all of which are located in Oklahoma.

 

 

 

At December 31, 2007, OG&E’s transmission system included: (i) 48 substations with a total capacity of approximately 9.5 million kilo Volt-Amps (“kVA”) and approximately 4,025 structure miles of lines in Oklahoma; and (ii) seven substations with a total capacity of approximately 2.5 million kVA and approximately 259 structure miles of lines in Arkansas. OG&E reclassified some substation assets as transmission assets that historically have been distribution assets. This was done in order to comply with the SPP’s FERC-approved transmission definition, which resulted in an increase in transmission substations and transformer capacity, as compared to 2006. OG&E’s distribution system included: (i) 342

 

35

 

---

substations with a total capacity of approximately 8.6 million kVA, 23,854 structure miles of overhead lines, 1,833 miles of underground conduit and 9,756 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of approximately 1.0 million kVA, 1,906 structure miles of overhead lines, 178 miles of underground conduit and 647 miles of underground conductors in Arkansas.

 

OG&E owns approximately 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73101. In addition to its executive offices, 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: (1) parcels that it owns in fee and (2) 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 continue to be held by 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, 2007, Enogex and its subsidiaries owned: (i) approximately 5,534 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas; (ii) approximately 2,318 miles of intrastate natural gas transportation pipelines in Oklahoma and Texas; (iii) two natural gas storage facilities in Oklahoma operating at a working gas level of approximately 23 Bcf with approximately 650 MMcf/d of maximum withdrawal capacity and approximately 650 MMcf/d of injection capacity; and (iv) six operating natural gas processing plants, with a total inlet capacity of approximately 723 MMcf/d, a 50 percent interest in an additional 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:

 

 

Enogex occupies approximately 109,493 square feet of office space at its executive offices at 600 Central Park Two, 515 Central Park Drive, Oklahoma City, Oklahoma 73105 under a lease that expires March 31, 2012. Although Enogex may

 

36

 

---

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 the 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, 2007, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $1.3 billion and gross retirements were approximately $305.8 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. The additions during this three-year period amounted to approximately 18.6 percent of total property, plant and equipment at December 31, 2007.

 

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 16 and 17 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 is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges:  (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the underreporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages:  (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

 

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

 

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

 

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

 

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and OG&E, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, the Company filed a notice of its intent to file a separate response brief, which the Company filed on

 

37

 

---

 

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

 

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

 

Recent Developments and Regulatory Matters

 

Proposed Acquisition of Power Plant

 

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

 

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

 

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

 

51

 

---

Cancelled Red Rock Power Plant

 

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

 

OCC Order Confirming Savings / Acquisition of McClain Power Plant

 

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

 

Pipeline Lease Project

 

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

 

MEP filed an application with the FERC on October 9, 2007 requesting a certificate of public convenience and necessity authorizing MEP to construct its pipeline and lease certain capacity from Enogex. On October 9, 2007, Enogex also filed an application with the FERC for issuance of a limited jurisdiction certificate authorizing its lease agreement with MEP. Certain Enogex shippers have filed motions to intervene in Enogex’s FERC certificate proceeding, and some have protested Enogex’s certificate application. Protestors have claimed that it is unduly discriminatory for Enogex to propose to lease capacity to MEP while not generally offering firm interstate transportation service, that the lease arrangement will adversely affect the availability of interruptible interstate transportation service on the Enogex system and that the lease payment specified under the MEP lease agreement is unduly preferential in MEP’s favor. These protestors have urged the FERC to reject the MEP lease arrangement or to condition its acceptance on a requirement that Enogex offer existing shippers taking interruptible interstate service the opportunity to convert that service to firm service. One protestor has asked the FERC to consolidate the Enogex certificate proceeding with Enogex’s Section 311 triennial rate proceeding currently pending before the FERC. While Enogex cannot predict what action the FERC may take regarding the lease agreement, Enogex believes that the proposed MEP lease arrangement is consistent with FERC policy and precedent involving similar lease arrangements.

 

On January 18, 2008, Enogex filed a 30-day advance notice to advise the FERC of its intended construction of the Bennington Station Facilities. In that notice, Enogex described the environmental impacts likely to be associated with construction and operation of a new 24,000 horsepower transmission compressor station and associated pipeline that Enogex proposes to construct to support its provision of pipeline capacity under its capacity leases including the lease with MEP. Enogex believes that it has complied with all applicable requirements of the FERC’s regulations pertaining to an intrastate

 

52

 

---

pipeline’s construction of facilities under Section 311 of the Natural Gas Policy Act, as amended. The FERC did not take any action with respect to Enogex’s advance notice filing and Enogex has begun construction of the Bennington Station Facilities.

 

Southeastern Oklahoma / East Side Expansions

 

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

 

Texas Panhandle / West Side Expansions

 

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

 

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

 

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

 

2008 Outlook

 

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

 

 

Key assumptions for 2008 are:

 

OG&E

 

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

 

 

53

 

---

 

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

 

Enogex

 

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

 

 

 

 

 

Holding Company

 

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

 

Dividend Policy

 

The Company’s dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends no more than 65 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. At the Company’s November 2007 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.3475 per share from $0.34 per share effective with the Company’s first quarter 2008 dividend.

 

Results of Operations

 

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the years ended December 31, 2007, 2006 and 2005 and the Company’s consolidated financial position at December 31, 2007 and 2006. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

 

54

 

---

 

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

 

Operating Income (Loss) by Business Segment

 

(A) Other Operations primarily includes consolidating eliminations.

 

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

 

55

 

---

OG&E

 

 

56

 

---

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

 

Gross Margin

 

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

 

 

These increases in the gross margin were partially offset by:

 

 

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

 

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

 

Operating Income

 

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

 

 

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

 

 

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

 

57

 

---

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

 

Additional Information

 

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

 

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

 

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

 

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

 

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

 

 

These decreases in interest expense were partially offset by:

 

 

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

 

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

 

 

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

 

 

58

 

---