(Mark One)

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

 

 

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

 

 

 

 

 

 

 

 

 

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OGE ENERGY CORP.

 

FORM 10-Q

 

FOR THE QUARTER ENDED SEPTEMBER 30, 2007

 

TABLE OF CONTENTS

 

 

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FORWARD-LOOKING STATEMENTS

 

Except for the  historical statements  contained  herein,  certain of the  matters  discussed in  this  Form
10-Q, including those matters discussed in “Item 2. 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 2. 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:

 

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PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements.

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

 

 

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

 

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

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OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

 

Organization

 

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. All significant intercompany transactions have been eliminated in consolidation.

 

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.

 

The operations of the natural gas transportation and storage, natural gas gathering and processing and natural gas marketing segments are part of the natural gas pipeline business conducted by Enogex Inc. and its subsidiaries (“Enogex”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma.

 

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

 

Formation of OGE Enogex Partners L.P.

 

In May 2007, the Company formed OGE Enogex Partners L.P., a Delaware limited partnership (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 Securities and Exchange Commission for a proposed initial public offering of its common units, representing limited partner interests in the Partnership (the “Offering”). At the date of this quarterly 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% membership interest in Enogex LLC to a wholly owned subsidiary of the Partnership that would serve as Enogex LLC’s managing member and will control its assets and operations. A wholly owned subsidiary of the Company will retain the remaining approximately 75% membership interest in Enogex LLC. It is currently contemplated that at the completion of the Offering, the Company will indirectly own a 64.0% limited partner interest and a 2% general partner interest in the Partnership. The Company will also own the Partnership’s general partner.

 

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 quarterly 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 September 30, 2007 (other than causing the Company to report four business segments rather than two (see Note 11)). 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 unit holders other than the Company or its consolidated subsidiaries.

 

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Basis of Presentation

 

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

 

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at September 30, 2007 and December 31, 2006, the results of its operations for the three and nine months ended September 30, 2007 and 2006, and the results of its cash flows for the nine months ended September 30, 2007 and 2006, have been included and are of a normal recurring nature.

 

Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2007 and 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company’s 2006 Form 10-K.

 

Accounting Records

 

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, 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 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.

 

 

 

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

 

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Price Risk Management Assets and Liabilities

 

In the second quarter of 2007, the Company adopted FASB Interpretation No. 39 (As Amended), “Offsetting of Amounts Related to Certain Contracts – an interpretation of APB Opinion No. 10 and FASB Statement No. 105,” which states that fair value amounts recognized for forward, interest rate swap, currency swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, currency swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the consolidated balance sheet. The Company has presented the fair values of its contracts under master netting agreements using a net fair value presentation. If these transactions with the same counterparty were presented on a gross basis in the Condensed Consolidated Balance Sheets, current Price Risk Management assets and liabilities would be approximately $17.2 million and $25.1 million, respectively, at September 30, 2007, and non-current Price Risk Management assets and liabilities would be approximately $7.1 million and $24.2 million, respectively, at September 30, 2007. If these transactions with the same counterparty were presented on a gross basis in the Condensed Consolidated Balance Sheets, current Price Risk Management assets and liabilities would be approximately $41.9 million and $9.2 million, respectively, at December 31, 2006, and non-current Price Risk Management assets and liabilities would be approximately $1.7 million and $1.1 million, respectively, at December 31, 2006.

 

Reclassifications

 

Certain prior year amounts have been reclassified on the Condensed Consolidated Financial Statements to conform to the 2007 presentation.

 

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the guidance in footnote 3 of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 should be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except in certain conditions. The Company will adopt this new standard effective January 1, 2008. Management does not expect the adoption of this interpretation to have a material impact on the Company’s consolidated financial position or results of operations.

 

 

On January 21, 1998, the Company adopted a Stock Incentive Plan (the “1998 Plan”). In 2003, the Company adopted, and its shareowners approved, a new Stock Incentive Plan (the “2003 Plan” and together with the 1998 Plan, the “Plans”). The 2003 Plan replaced the 1998 Plan and no further awards will be granted under the 1998 Plan. As under the 1998 Plan, under the 2003 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 2,700,000 shares under the 2003 Plan.

 

Effective January 1, 2006, the Company adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective transition method. Under that transition method, compensation cost recognized in the first quarter of 2006 included: (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R); and (ii) compensation cost for all share-based payments granted in the first quarter of 2006 based on the fair value calculated in accordance with the provisions of SFAS No. 123(R).

 

As a result of adopting SFAS No. 123(R) on January 1, 2006, the Company recorded compensation expense of approximately $1.6 million pre-tax ($1.0 million after tax, or $0.01 per basic and diluted share) and approximately $6.0 million pre-tax ($3.7 million after tax, or $0.04 per basic and diluted share) during the three and nine months ended September 30, 2006,

 

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respectively, related to the Company’s share-based payments. Also, as a result of adopting SFAS No. 123(R), the Company recorded a cumulative effect adjustment of approximately $0.4 million pre-tax ($0.2 million after tax, or less than $0.01 per basic and diluted share) on January 1, 2006 for outstanding non-vested share-based compensation grants at December 31, 2005. The Company determined that the cumulative effect adjustment was immaterial for presentation purposes and is, therefore, included in Other Operation and Maintenance Expense in the Condensed Consolidated Statement of Income. The Company recorded compensation expense of approximately $0.9 million pre-tax ($0.5 million after tax, or $0.01 per basic and diluted share) and approximately $2.3 million pre-tax ($1.4 million after tax, or $0.02 per basic and diluted share), respectively, during the three and nine months ended September 30, 2007 related to the Company’s share-based payments.

 

The Company issues new shares to satisfy stock option exercises. During the three and nine months ended September 30, 2007, respectively, there were 37,500 shares and 334,639 shares of new common stock issued pursuant to the Company’s Plans related to exercised stock options. The Company received approximately $0.9 million and $4.2 million during the three months ended September 30, 2007 and 2006, respectively, and approximately $8.0 million and $10.3 million during the nine months ended September 30, 2007 and 2006, respectively, related to exercised stock options.

 

The Company recorded an excess tax benefit of approximately $0.1 million and $0.9 million during the three and nine months ended September 30, 2007, respectively, related to the Company’s 2007 share-based payments. The Company realized an excess tax benefit of approximately $2.8 million during each of the three and nine month periods ended September 30, 2007, related to the Company’s 2006 share-based payments, which amount was presented as a financing cash inflow and realized when the Company’s 2006 income tax return was filed in September 2007. The Company recorded an excess tax benefit of approximately $0.7 million and $1.8 million during the three and nine months ended September 30, 2006, respectively, related to the Company’s 2006 share-based payments. The Company realized an excess tax benefit of approximately $1.4 million during each of the three and nine month periods ended September 30, 2006, related to the Company’s 2005 share-based payments, which amount was presented as a financing cash inflow and realized when the Company’s 2005 income tax return was filed in August 2006.

 

 

The components of total comprehensive income for the three and nine months ended September 30, 2007 and 2006, respectively, are as follows:

 

 

 

 

 

 

 

 

 

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In March 2006, Enogex announced that its wholly owned subsidiary, Enogex Gas Gathering L.L.C., had entered into an agreement to sell certain gas gathering assets in the Kinta, Oklahoma, area. The assets included in the transaction were approximately 568 miles of gas gathering pipeline and 22 compressor units with current volumes of approximately 145 million cubic feet per day, all in eastern Oklahoma. The sale price was approximately $93 million. This transaction closed on May 1, 2006 and Enogex recorded an after tax gain of approximately $34.1 million during the second quarter of 2006. The proceeds from the sale, were used, among other things, to reduce short-term debt levels and fund capital expenditures.

 

The Condensed Consolidated Financial Statements of the Company have been reclassified to reflect the sale of these assets in Kinta, Oklahoma, which were part of the natural gas transportation and storage and gathering and processing segments, as discontinued operations. Accordingly, revenues, costs and expenses and cash flows of these assets that were sold have been excluded from the respective captions in the Condensed Consolidated Financial Statements and have been separately reported as discontinued operations in the applicable financial statement captions. Summarized financial information for the discontinued operations as of September 30 is as follows:

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME DATA

 

 

 

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2001. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its federal investment tax credits on a ratable basis throughout the year. This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income. The following schedule reconciles the statutory federal tax rate to the effective income tax rate:

 

 

 

 

 

 

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(A) These are credits OG&E began earning associated with the production from its 120 megawatt (“MW”) wind farm in northwestern Oklahoma (“Centennial”) that was placed in service during January 2007.

 

In connection with the filing in the third quarter of 2003 of the Company’s consolidated income tax returns for 2002, OG&E elected to change its tax method of accounting related to the capitalization of costs for self-constructed assets to another method prescribed in the Income Tax regulations. The accounting method change was for income tax purposes only. For financial accounting purposes, the only change was recognition of the impact of the cash flow generated by accelerating income tax deductions. This was reflected in the financial statements as a switch from current income taxes payable to deferred income taxes payable. This tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under the prior method, resulting in a consolidated tax net operating loss for 2002. This tax net operating loss eliminated the Company’s current federal and state income tax liability for 2002 and 2003 and all estimated payments made for 2002 were refunded. The Company received federal and state income tax refunds of approximately $50.8 million during 2003 related to this tax accounting method change.

 

During 2005, new guidelines were issued by the Internal Revenue Service (“IRS”) related to the change in the method of accounting used to capitalize costs for self-construction discussed above. The Company’s current IRS examination process for years 2002 and 2003, which was completed in the second quarter of 2006, identified this change in method of accounting as an issue under examination. As a result of their examination, the IRS disagreed with the change OG&E made in 2002 and determined that OG&E should change its tax method of accounting for the capitalization of costs for self-constructed assets to another method prescribed in the Income Tax regulations. The Company filed a formal protest with the IRS on July 21, 2006 (related to the 2002 and 2003 examination) requesting a hearing with the IRS to review the IRS’s determination that the tax accounting method OG&E elected in 2002 was not appropriate. On August 17, 2006, the Company made a deposit with the IRS in anticipation that a portion of prior year deductions will be disallowed. During the first quarter of 2007, the IRS concluded its examination of the 2004 tax year and proposed significant adjustments related to the same method of accounting issue as the previous two years. The Company continues to disagree with the adjustments and filed a separate protest on April 2, 2007 related to the 2004 tax year. The impact of this matter on future cash flows is uncertain but could be material.

 

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized approximately a $3.8 million increase in the accrued interest liability, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility (see discussion of the tax method of accounting for the capitalization of costs for self-constructed assets above). Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company believes it is reasonably possible to arrive at a settlement with the IRS related to the tax method of accounting for the capitalization of costs for self-constructed assets within the next 12 months. Until the Company arrives at an ultimate settlement, the Company will continue to accrue interest related to the uncertainty.

 

The Company recognizes accrued interest related to unrecognized tax benefits in interest expense and recognizes penalties in other expense. During the three months ended September 30, 2007 and 2006, OG&E recorded approximately $0.8 million pre-tax ($0.5 million after tax, or $0.01 per basic and diluted share) and $0.4 million pre-tax ($0.2 million after tax, or less than $0.01 per basic and diluted share) in interest, respectively. During the nine months ended September 30, 2007 and 2006, OG&E recorded approximately $2.4 million pre-tax ($1.5 million after tax, or $0.02 per basic and diluted share) and $0.3 million pre-tax ($0.2 million after tax, or less than $0.01 per basic and diluted share) in interest, respectively. At September 30, 2007 and December 31, 2006, the Company had approximately $12.1 million and $3.5 million, respectively, of accrued interest related to the capitalization of costs for self-constructed assets discussed above.

 

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

 

 

Outstanding shares for purposes of basic and diluted earnings per average common share were calculated as follows:

 

 

 

At September 30, 2007, the Company was in compliance with all of its debt agreements.

 

Long-Term Debt with Optional Redemption Provisions

 

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

 

 

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

 

 

 

 

 

 

 

 

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The short-term debt balance was approximately $158.9 million at September 30, 2007. There was no short-term debt outstanding at December 31, 2006. The following table shows the Company’s revolving credit agreements and available cash at September 30, 2007.

 

 

The Company’s and OG&E’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions as experienced with the market turmoil in August 2007. As a result of the market turmoil in August 2007, the Company utilized borrowings under its revolving credit agreements. When the market returned to normal operations, the Company repaid the borrowings under its revolving credit agreements and began utilizing commercial paper in the commercial paper market. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the ratings of the Company or OG&E would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of Enogex would also lead to higher borrowing costs and, if below investment grade, would require Enogex to post cash collateral or letters of credit. Also, as reported in the Company’s 2006 Form 10-K, any downgrade below investment grade at Enogex could require the Company to issue guarantees on behalf of Enogex to support some of OGE Energy Resources, Inc.’s (“OERI”), a wholly owned subsidiary of Enogex, marketing operations.

 

Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2007 and ending December 31, 2008.

 

 

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R),” which requires an employer to: (i) recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity; and (ii) measure the fair value of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements were effective for the year ended December 31, 2006 for the Company. The requirement to measure plan assets and benefit obligations at fair value as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 also requires additional disclosures for defined benefit pension plans and other defined benefit postretirement plans.

 

 

 

 

 

 

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The details of net periodic benefit cost of the pension plan (including the restoration of retirement income plan) and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

 

  Net Periodic Benefit Cost

 

Retirement Restoration Plan Settlement Charge

 

In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic retirement restoration cost. During the third quarter of 2007, the Company recorded a retirement restoration plan settlement charge of approximately $3.0 million primarily due to the death of the Company’s Chairman and Chief Executive Officer in September 2007. The retirement restoration settlement charge did not require a cash outlay by the Company and did not increase the Company’s total retirement restoration expense over time, as the charge was an acceleration of costs that otherwise would have been recognized as retirement restoration expense in future periods. OG&E’s Oklahoma jurisdictional portion of this charge was recorded as a regulatory asset.

 

Pension Plan Funding

 

In the third quarter of 2007, the Company contributed approximately $10 million to its pension plan for a total contribution of $50 million to its pension plan during 2007. No additional contributions are expected in 2007.

 

 

Historically, the Company’s business was divided into two reportable segments, electric utility and natural gas pipeline. However, the Company has provided supplemental revenue and operating income information for each of the three businesses in Enogex’s natural gas pipeline segment. As part of the process of preparing the registration statement on Form S-1 for OGE Enogex Partners L.P. that was filed on June 27, 2007 and as discussed in Note 1 above, the Company determined that, for reporting purposes, Enogex, as a stand-alone entity, had three segments – (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Therefore, beginning with the second quarter of 2007, the Company’s business is now divided into four reportable segments for reporting purposes. These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) the transportation and storage of

 

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natural gas, (iii) the gathering and processing of natural gas and (iv) the marketing of natural gas. Other Operations for the three and nine months ended September 30, 2007 and 2006 primarily included consolidating eliminations. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and therefore has presented this information below. The following tables summarize the results of the Company’s business segments for the three and nine months ended September 30, 2007 and 2006. The results of the Company’s business segments have been restated for all prior periods presented to conform to the 2007 presentation.

 

 

 

 

 

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Except as set forth below and in Note 13, the circumstances set forth in Notes 17 and 18 to the Company’s Consolidated Financial Statements included in the Company’s 2006 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.

 

Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C.

 

Cheyenne Plains Gas Pipeline Company, L.L.C (“Cheyenne Plains”) operates the Cheyenne Plains Pipeline that provides firm transportation services in Wyoming, Colorado and Kansas with a capacity of 730,000 decatherms/day (“Dth/day”). OERI entered into a Firm Transportation Service Agreement (“FTSA”) with Cheyenne Plains in 2004, for 60,000 Dth/day of firm capacity on the Cheyenne Plains Pipeline. The FTSA was for a 10-year term beginning with the in-service date of the Cheyenne Plains Pipeline in March 2005 with an annual demand fee of approximately $7.4 million. Effective March 1, 2007, OERI and Cheyenne Plains amended the FTSA to provide for OERI to turn back 20,000 Dth/day of its capacity beginning in January 2008 for the remainder of the term. OERI’s new demand fee obligations, net of this turn back and other immaterial release agreements, are estimated at approximately $6.9 million in 2007; $5.9 million in 2008; $6.5 million for each of the years 2009 through 2014; and $1.6 million in 2015.

 

Agreement with Midcontinent Express Pipeline, LLC

 

On December 15, 2006, Enogex announced that it had entered into a firm capacity lease agreement with Midcontinent Express Pipeline, LLC for a primary term of 10 years (subject to possible extensions) for capacity on the Enogex system. The leased capacity provided for in this agreement is up to 500 million cubic feet per day and is dependent on the shipper volumes that commit to the project. Enogex’s capacity will be a part of the proposed Midcontinent Express Pipeline (“MEP”), a joint venture between Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. In addition to Enogex’s leased capacity, the proposed MEP project includes 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 during 2007 and 2008 will be between $65 million and $100 million. Enogex’s lease agreement with MEP is subject to certain contingencies including regulatory approval. Prior to such 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 its application with the FERC on October 9, 2007 requesting authorization to construct and lease certain facilities relating to its pipeline. On October 9, 2007, Enogex also filed its application with the FERC requesting approval of its lease agreement with MEP.

 

Purchased Power

 

In March 2007, OG&E issued a request for proposal for capacity and/or firm energy purchases for the summer periods of 2008 through 2010. Completion of the process is expected in the fourth quarter of 2007 and is subject to review by the OCC.

 

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Natural Gas Measurement Cases

 

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

 

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

 

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

 

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of 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 for other legal costs on December 18, 2006. The defendants filed motions for attorneys’ fees regarding issues of liability and Rule 11 motions on January 8, 2007. 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 an appellants’ opening brief on July 31, 2007. The appellees’ consolidated response brief is due on November 21, 2007. At this time, oral arguments are preliminarily scheduled during the week of May 12, 2008. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

 

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

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005.

 

In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

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On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiaries of Enogex filed their proposed findings of fact and

 

conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.

 

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

 

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II). On May 12, 2003, the plaintiffs (same as those in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the amended petition of the Price I case. The plaintiffs allege that the defendants mismeasured the British thermal unit content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005.

 

In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

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

 

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

 

Calpine Corporation Bankruptcy

 

Calpine Corporation, Calpine Energy Services, L.P., and several other affiliates (collectively “Calpine”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on December 20, 2005 (Case No. 05-60200 (BRL)) in the United States Bankruptcy Court, Southern District of New York (the “Bankruptcy Court”).  Enogex provides natural gas transportation services pursuant to long-term contracts to two Calpine-owned power generation plants in Oklahoma. Calpine is continuing to operate the plants and request services pursuant to the contracts. The total unpaid amount due to Enogex from Calpine is approximately $0.3 million which has been fully reserved on the Company’s books.  

 

During October 2007, Calpine and Enogex agreed to and executed amended and restated contracts extending the primary terms, reducing the volume of firm transportation and including authorized overrun charges for additional capacity utilized. As part of the agreements, approximately $0.2 million of the bankruptcy claim will be paid in November 2007 and the remaining $0.1 million will be allowed as a general unsecured claim under the bankruptcy plan. The amended and restated contracts were presented to and approved by the Bankruptcy Court on October 19, 2007. The Bankruptcy Court order became final on October 30, 2007 and the payment of the general allowed unsecured claim ($0.1 million) is currently expected to be paid in the first quarter of 2008.

 

A Calpine-owned power generation plant in Oklahoma is contractually obligated to provide capacity and energy to OG&E; however, the contract terminates on December 31, 2007. The Calpine plant also pays, through the Southwest Power Pool (“SPP”), for transmission services provided by OG&E. OG&E expects the capacity and energy arrangements to remain in effect until the end of 2007; however, whether Calpine will subsequently continue to require transmission services from OG&E is unknown.

 

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Environmental Laws and Regulations

 

OG&E

 

Air

 

On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On May 31, 2006, the EPA issued a ruling which amended and clarified minor portions of the CAMR. The CAMR is currently subject to legal challenges. The CAMR requires reductions in mercury in two phases, Phase I beginning in 2010 and Phase II beginning in 2018. The CAMR includes a cap and trade program that will allow utilities to purchase mercury allowances (if available) rather than reduce emissions. It is anticipated that OG&E will need to obtain allowances or reduce its mercury emissions in Phase II by approximately 70 percent. The CAMR requires each state to adopt the requirements of the federal rule into a state implementation plan. However, the CAMR does not preclude states from developing more stringent mercury reduction requirements. The state of Oklahoma has proposed to incorporate the EPA’s CAMR, along with the proposed mercury allowance allocations, into the state implementation program. OG&E is currently participating in the state rulemaking process and anticipates the rulemaking to be completed in 2008. The proposed Oklahoma rule was delayed due to public objection to the proposed rule and uncertainty about the outcome of ongoing litigation of the CAMR at the federal level. Because rulemaking is in progress, the cost to install any mercury controls is uncertain at this time but is expected to be significant to meet Phase II requirements in 2018. The CAMR and the proposed state implementation plan will also require continuous monitoring of mercury emissions from OG&E’s coal-fired boilers beginning in 2009. The cost of the monitoring equipment is estimated at approximately $6.0 million, which is expected to be incurred during years 2007 and 2008. At September 30, 2007, OG&E has incurred approximately $3.6 million for the monitoring equipment. However, the cost of the monitoring systems could increase or decrease based on the technology being used in the equipment and related certification costs. The cost to comply with the CAMR monitoring requirements will be in addition to the cost of other emissions monitoring that is already in place pursuant to Title IV of the Clean Air Act Amendments of 1990.

 

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States.  In Oklahoma, the Wichita Mountains are the only area covered under the regulation. However, Oklahoma’s impact on parks in other states must also be evaluated. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. The state of Oklahoma has joined with eight other central states to address these visibility impacts.

 

In September 2005, the Oklahoma Department of Environmental Quality (“ODEQ”) informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have “Best Available Retrofit Technology (“BART”) eligible sources” (sources built between 1962 and 1977). For OG&E, these include various generating units at various generating stations. Regulations, however, allow an owner or operator of a BART-eligible source to request and obtain a waiver from BART if modeling shows no significant impact on visibility in nearby Class I areas. Based on this modeling, the ODEQ made a preliminary determination to accept an application for a waiver for the Horseshoe Lake generating station. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan that must be submitted for the EPA approval by December 17, 2007. It is not known whether approval for the state implementation plan will be granted by the EPA.

 

The modeling did not support waivers for the affected units at the Seminole, Muskogee and Sooner generating stations. OG&E submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, OG&E submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants will achieve overall greater visibility improvement than BART in the affected Class I areas and the alternative plan extends the timeline for compliance to 2018. The estimated cost for this alternative plan and the BART compliance plan for the Seminole power plant is approximately $470 million. The alternative compliance plan includes installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan is subject to approval by the ODEQ and the EPA. The EPA provided a preliminary opinion to the ODEQ that OG&E’s alternative compliance plan may not meet the requirements of the regional haze rules. The EPA recommended that OG&E complete additional modeling supporting its alternative plan. OG&E plans to spend approximately $0.2 million during 2007 related to the regional haze project. The cost to comply with the regional haze regulations could increase or decrease substantially based on the interpretation of the requirements by the ODEQ and the EPA, the availability of alternative control measures to achieve more cost effective visibility improvements, the availability of materials, labor force and the specific design criteria for OG&E’s generating units. OG&E expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E’s retail customers under House Bill 1910, which was enacted into law in May 2005.

 

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With respect to the NOX regulations of the acid rain program, OG&E committed to meeting a 0.45 lbs/million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a result, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E’s average NOX emissions from its coal-fired boilers for 2006 were approximately 0.33 lbs/MMBtu. The regulations require that OG&E achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers beginning in 2008. It is expected that NOX emissions will be further reduced to 0.15 lbs/MMBtu by 2016 if the regional haze compliance plan discussed above is approved by the EPA. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are impacting the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma becomes non-attainment with the fine particulate standard. Any of these scenarios would likely require significant capital and operating expenditures.

 

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone. However, future elevated readings could lead to redefinition of these areas as non-attainment. Both Tulsa and Oklahoma City have entered into an “Early Action Compact” with the EPA whereby voluntary measures are required to be enacted to reduce ozone. This compact expires in December 2007. However, the EPA has proposed continuation through a similar program called Ozone Flex, in which both Oklahoma City and Tulsa are expected to participate. Currently, the EPA is reevaluating the current ozone standard and proposed further reductions in the ambient standard on September 20, 2007. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.

 

Water

 

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA Section 316(b) rules for existing facilities became effective July 23, 2004. OG&E has engaged a consultant who has developed the required documentation for four OG&E facilities. These documents were submitted to the state agency on December 7, 2005 for review and approval. OG&E has also provided the state of Oklahoma with information and requests that, if approved by the state, may reduce the impact of the Section 316(b) rules on OG&E. On January 25, 2007, a federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the state of Oklahoma indicated that it is requiring a comprehensive demonstration study be submitted by January 8, 2008 for each affected facility. It is not clear what changes, if any, the EPA will ultimately make to the Section 316(b) rules or how those changes may affect OG&E. Depending on the ultimate analysis and final determinations regarding the Section 316(b) rules and the Oklahoma comprehensive demonstration study, capital and/or operating costs may increase at any affected OG&E generating facility.

 

Other

 

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed Consolidated Financial Statements. Except as otherwise stated above, in Note 13 below, in Item 1 of Part II of this Form 10-Q, in Notes 17 and 18 of Notes to the Company’s Consolidated Financial Statements included in the Company’s 2006 Form 10-K and in Item 3 of that report, 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.

 

 

Except as set forth below, the circumstances set forth in Note 18 to the Company’s Consolidated Financial Statements included in the Company’s 2006 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

 

Completed Regulatory Matters

 

OCC Order Confirming Savings / Acquisition of 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

 

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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. In August 2003, OG&E signed an agreement to purchase a 77 percent interest in the 520 MW natural gas-fired combined cycle NRG McClain Station (“McClain Plant”), but due to a delay at the FERC, the acquisition was not completed by December 31, 2003. In the interim, OG&E entered into a power purchase agreement with the McClain Plant that delivered the savings guaranteed to OG&E’s customers. OG&E requested that the OCC confirm that the steps it had taken, including the power purchase agreement, were satisfying the customer savings obligation under the 2002 Settlement Agreement and that OG&E would not be required to begin crediting its customers. On April 28, 2004, the OCC issued an order confirming that OG&E was delivering savings to its customers as required under the 2002 Settlement Agreement. The order removed any uncertainty over whether the OCC believed OG&E had to reduce its rates, effective January 1, 2004, while it awaited action by the FERC on its application to purchase the McClain Plant. A party to the OCC proceeding appealed the OCC’s order to the Oklahoma Supreme Court. The appeal was denied and the OCC order is considered final.

 

On July 9, 2004, OG&E completed the acquisition of a 77 percent interest in the McClain Plant. This transaction 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 in which OG&E stated that the acquisition of the McClain Plant provided savings to its Oklahoma customers in excess of $177 million over the three-year period of January 1, 2004 through December 31, 2006. In the event the OCC concludes that OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will be required to credit its Oklahoma customers any unrealized savings below $75.0 million. On October 31, 2007, a settlement agreement was reached with the parties in this matter that OG&E provided at least $75.0 million in savings to its customers over the three-year period. A hearing is scheduled for November 1, 2007. OG&E expects the OCC to issue an order by the end of 2007 in this matter.

 

Security Enhancements

 

On April 8, 2002, OG&E filed a joint application with the OCC Staff requesting approval for security investments and a rider to recover these costs from the ratepayers. On October 28, 2004, all parties signed a joint stipulation that contains the OCC Staff’s recommendations and authorizes up to a $5 million annual recovery from OG&E’s customers for security enhancement. On December 21, 2004, the OCC issued an order approving the stipulation, which included a security rider. OG&E implemented the security rider with the first billing period in July 2006 and began charging OG&E’s Oklahoma customers approximately $2.4 million annually. The OCC authorized tariff provides that the security rider may be updated quarterly. In December 2006, OG&E updated the security rider to recover approximately $2.9 million annually beginning with the first billing cycle in January 2007. OG&E also filed an application with the OCC on December 15, 2006 to amend its security plan to seek approval of approximately $7.6 million of cost increases related to the expanded scope of previously authorized projects and approximately $10.9 million for new security projects with an associated annual revenue requirement of approximately $2.7 million. On May 16, 2007, a settlement agreement was reached with the parties in this matter recommending approximately $17.6 million of security capital expenditures and the associated revenue requirement of approximately $2.6 million. On June 26, 2007, the OCC issued an order which approved the settlement agreement with new rates being implemented during the first billing cycle of July 2007.

 

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2005

 

The OCC routinely audits activity in OG&E’s fuel adjustment clause for each calendar year. In October 2006, the OCC Staff filed an application for a review of OG&E’s 2005 fuel adjustment clause. On July 12, 2007, the OCC Staff filed testimony that OG&E was in compliance with its authorized fuel adjustment clause for calendar year 2005. A hearing was held in August 2007 and the OCC issued an order in September 2007 approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2005.

 

Cogeneration Credit Rider

 

On September 17, 2004, OG&E filed an application and testimony with the OCC requesting a cogeneration credit rider. The requested rider reduces cogeneration charges to customers because of decreasing cogeneration payments made by OG&E beginning January 2005. The cogeneration credit rider is necessary because amounts currently recovered from customers in base rates include historically higher cogeneration payments. OG&E’s cogeneration credit rider has been updated and approved by the OCC in December of each year through December 2006 and any over/under recovery of the cogeneration credit rider in the current year and prior periods has been automatically included in the next year’s rider. OG&E’s current cogeneration credit rider expires December 31, 2007. The 2007 cogeneration credit rider, filed with the OCC, of approximately $80.7 million is partially

 

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offset by the prior year under recovery of approximately $2.5 million. OG&E filed an application with the OCC in September 2007 to request a new cogeneration credit rider for years after 2007.

 

OG&E Wind Power Filing

 

In January 2007, OG&E’s 120 MW Centennial wind farm was fully in service. From January 1, 2007 through September 30, 2007, OG&E spent approximately $32.7 million related to the Centennial wind farm for total expenditures in 2006 and 2007 of approximately $203.7 million. The OCC previously issued its order approving a settlement agreement relating to the Centennial wind power contract and authorizing a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. The settlement also indicated that OG&E shall file for a general rate review during 2009 that will permit the OCC to issue an order no later than December 31, 2009 placing the Centennial wind farm in OG&E’s rate base. Pursuant to the settlement agreement, OG&E sent notice to the OCC on January 17, 2007 informing the OCC that the Centennial wind farm was operational, triggering the recovery rider for the first billing cycle in February 2007. The recovery rider is designed to recover the lower of a capped or actual revenue requirement including a return on equity of 10.75 percent. OG&E expects the recovery rider to remain in effect through late 2009. Also, the rate order from the APSC discussed below allows for the recovery of the portion of the Centennial wind farm allocable to OG&E’s customers in Arkansas.

 

OG&E Arkansas Rate Case Filing

 

On July 28, 2006, OG&E filed with the APSC an application for an annual rate increase of approximately $13.5 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant, the Centennial wind power project and the costs of electric system expansion and upgrades based on a return on equity of 11.75 percent. On November 29, 2006, OG&E reached a settlement with the other parties in this case for an annual rate increase of approximately $5.4 million. In the settlement agreement, the parties also agreed that OG&E would be allowed to recover the full Arkansas portion of the Centennial wind farm. On January 5, 2007, the APSC approved the settlement and issued a rate order that provides for a $5.4 million annual increase in OG&E’s electric rates and a 10.0 percent return on equity. The Arkansas rates became effective in February 2007.

 

OG&E FERC Audit

 

On May 29, 2006, the FERC notified OG&E that it was commencing an audit to determine whether and how OG&E is complying with: (i) its Open Access Transmission Tariff; (ii) requirements of its market-based rate authorization; (iii) Standards of Conduct and Open Access Same-Time Information System; and (iv) wholesale fuel adjustment clause tariff and other requirements contained in the FERC regulations. Over the past several years, the FERC has conducted numerous audits of utilities across the country to ensure regulatory compliance. On June 29, 2007, the FERC issued its final audit report. In its report, the FERC made a limited set of findings and recommended certain actions that OG&E has implemented. Among its findings, the FERC concluded that OG&E did not make the appropriate refunds to certain wholesale customers subsequent to the OCC issuing an order changing the amount of storage costs in OG&E’s gas transportation and storage agreement with Enogex that are recoverable from Oklahoma retail customers.  As a result, OG&E recomputed billings made after May 2003 to certain wholesale customers and issued refunds in accordance with the FERC regulations.  The total amount of the refunds was approximately $1.0 million, including interest, which OG&E had fully reserved on its books in December 2006.

 

Enogex FERC Audit

 

On May 29, 2007, the FERC notified Enogex that it was commencing an audit to determine whether and how Enogex has complied with periodic regulatory reporting requirements for intrastate pipelines. On the same day that the FERC contacted Enogex, the FERC also notified a number of other intrastate pipelines and storage entities with market-based rates 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 the 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.

 

Southwest Power Pool

 

The SPP filed with the FERC on June 15, 2005, Docket No. ER05-1118, to create a real-time, offer-based energy imbalance service market that will require cash settlements for over or under generation. Market participants, including OG&E, will be required to submit resource plans and can submit offer curves for each resource available for dispatch. In addition, the SPP may order certain dispatching of generating units and has implemented a market monitoring plan that provides a clear set of rules, the potential consequences if the rules are violated and the areas in which an independent market monitor will examine and report. On March 20, 2006, the FERC issued an order that conditionally accepted a portion of the filing and suspended and

 

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rejected other portions of the filing. After several delays, the SPP Board of Directors voted to implement the energy imbalance service market no earlier than February 1, 2007. The SPP filed a certification of readiness to the FERC on January 18, 2007 that addressed issues raised by intervenors to the proceeding. The SPP energy imbalance service market began operations on February 1, 2007. As one condition to participation in the energy imbalance service market, OG&E, as well as other balancing authorities in the SPP, were required to submit open access tariff schedules setting forth the rates, terms and conditions for the provision of emergency energy service. OG&E submitted the required schedule on September 13, 2006, in Docket No. ER06-1488-000. On January 31, 2007, the FERC issued an order conditionally accepting OG&E’s proposed emergency energy schedule, subject to OG&E submitting, within 30 days, a compliance filing making certain revisions required by the FERC. On March 6, 2007, OG&E filed its compliance filing. On May 4, 2007, the FERC accepted OG&E’s compliance filing with an effective date of February 1, 2007. Parties in this matter had 30 days to request a rehearing. No request for rehearing was filed with the FERC and OG&E believes the order is final.

 

Pending Regulatory Matters

 

Cancelled Red Rock Power Plant

 

On September 10, 2007, the OCC denied 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”). The OCC’s Administrative Law Judge (“ALJ”) had previously reviewed the proposal and supported the project. However, final approval rested with the three OCC commissioners. On October 11, 2007, the OCC issued an order verifying their September 10, 2007 recommendation to deny the request for pre-approval of the proposed Red Rock power plant project. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At September 30, 2007, OG&E has incurred approximately $17.6 million of capitalized costs associated with the Red Rock power plant project. OG&E expects to file an application with the OCC requesting authorization to defer and propose a plan for recovery of approximately $15.4 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 Condensed Consolidated Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. OG&E is considering various options to meet its service territory’s power needs in the future.

 

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2006

 

The OCC routinely audits activity in OG&E’s fuel adjustment clause for each calendar year. In September 2007, the OCC Staff filed an application for a prudence review of OG&E’s 2006 fuel adjustment clause. OG&E is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, OG&E has requested an extension to file the MFR’s in January 2008. In October 2007, the ALJ recommended approval of OG&E’s request for an extension of time to file the MFR’s. OG&E received an order approving the extension from the OCC in October 2007. A procedural schedule has not yet been issued in this matter.

 

Enogex FERC Section 311 2007 Rate Case

 

On October 1, 2007, Enogex made its required triennial 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 requests an increase in the maximum zonal rates and proposes to place such rates into effect on January 1, 2008. Interested parties had until October 22, 2007 to intervene and protest. Thus far, seven parties have intervened and six parties have filed protests. In the normal course, the FERC Staff and intervenors will 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 will, thereafter, undertake settlement discussions. There is no statutory deadline by which the FERC must act. The regulations provide that the FERC has 150 days to act on the filing or issue an order extending the time period for action.

 

Market-Based Rate Authority

 

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

 

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

 

On March 21, 2006, the FERC issued an order conditionally accepting OG&E’s and OERI’s proposal to mitigate the presumption of market power in OG&E’s control area. First, the FERC accepted the additional information related to first-tier markets submitted by OG&E and OERI, and concluded that OG&E and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within OG&E’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within OG&E’s control area (instead of only to sales sinking to load within OG&E’s control area). On April 20, 2006, the Company submitted: (i) a compliance filing containing the specified revisions to the Company’s market-based rate tariffs and the new cost-based rate tariff; and (ii) a request for rehearing asking the FERC to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the FERC issued a tolling order that effectively provided the FERC additional time to consider the April 20, 2006 rehearing request. On July 25, 2006 and August 25, 2006, pursuant to a FERC March 20, 2006 order, OG&E and OERI filed revisions to their market-based rate tariffs to allow them to sell energy imbalance service into the wholesale markets administered by the SPP at market-based rates. The FERC has not yet acted on OG&E’s April 20, 2006, July 25, 2006 or August 25, 2006 filings. On February 6, 2007, OG&E and OERI submitted to the FERC a change in status report notifying the FERC that OG&E has placed into service OG&E’s Centennial wind farm, a wind farm with a nameplate capacity rating of 120 MW. OG&E and OERI explained that adding this capacity was not material to the FERC’s grant of market-based rate status to OG&E and OERI. On March 9, 2007, the FERC accepted OG&E’s and OERI’s change of status filing. On June 21, 2007, the FERC issued a final rule codifying and revising standards for market-based rate sales of electric energy, capacity and ancillary services. This final rule clarifies the scope of the mitigation applicable to sales within OG&E’s control area. OG&E began complying with the final rule and must formally incorporate certain provisions into its market-based rate tariff the next time OG&E proposes a tariff change, makes a change in status filing or submits an updated market power analysis.

 

North American Electric Reliability Council

 

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC has approved the North American Electric Reliability Council (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. On April 19, 2007, the FERC approved the SPP as a Regional Entity whose primary function is to review and enforce compliance of reliability standards with all registered entities in the region. In March 2007, the FERC approved mandatory NERC reliability standards which became effective June 18, 2007. OG&E recently completed a NERC audit and expects a report to be issued by the NERC in November 2007. The Company is subject to a NERC readiness evaluation and compliance audit every three years. The next compliance audit is scheduled for 2008 and the next readiness evaluation is scheduled for 2010.

 

National Legislative Initiatives

 

In June 2007, the United States Senate approved a bill that largely focused on increasing energy efficiency standards for the use of electricity in appliances, residential and commercial buildings. Also, the United States House of Representatives is currently discussing a bill addressing, among other things, smart grid development, increased use of cogeneration, extension of tax credits for renewable energy generation such as wind and solar, tax incentives for plug in hybrid vehicle development and accelerated depreciation for investment in smart meters.

 

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State Legislative Initiatives

 

In the 2007 legislative session, a bill was introduced in the Oklahoma legislature which proposed that electric utilities record fuel or natural gas removed from storage using the weighted-average cost method of accounting for inventory. Historically, the Company has used the last-in, first-out method of accounting for inventory removed from storage. This bill passed the legislature and was signed into law on June 5, 2007 and is effective January 1, 2008. Management does not believe the impact of this accounting change will be material to its consolidated financial position and results of operations. OG&E filed an application with the OCC in September 2007 to address the accounting issues for the change in accounting for fuel inventory.

 

 

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, which have significantly changed since December 31, 2006.

 

 

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swaps and energy trading contracts was determined primarily based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties and the potential impact of liquidating the position in an orderly manner over a reasonable period of time. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Introduction

 

OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.

 

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.

 

The operations of the natural gas transportation and storage, natural gas gathering and processing and natural gas marketing segments are part of the natural gas pipeline business conducted by Enogex Inc. and its subsidiaries (“Enogex”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma.

 

Formation of OGE Enogex Partners L.P.

 

In May 2007, the Company formed OGE Enogex Partners L.P., a Delaware limited partnership (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 Securities and Exchange Commission for a proposed initial public offering of its common units,

 

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representing limited partner interests in the Partnership (the “Offering”). At the date of this quarterly 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% membership interest in Enogex LLC to a wholly owned subsidiary of the Partnership that would serve as Enogex LLC’s managing member and will control its assets and operations. A wholly owned subsidiary of the Company will retain the remaining approximately 75% membership interest in Enogex LLC. It is currently contemplated that at the completion of the Offering, the Company will indirectly own a 64.0% limited partner interest and a 2% general partner interest in the Partnership. The Company will also own the Partnership’s general partner.

 

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 quarterly 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 September 30, 2007 (other than causing the Company to report four business segments rather than two (see Note 11 of Notes to Condensed Consolidated Financial Statements). 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.

 

Wind Power Initiative

 

On October 30, 2007, the Company announced its goal to increase its wind power generation over the next four years from its current 170 megawatts (“MW”) to 770 MW’s. The Company also announced its desire to begin building a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early 2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle. This high-capacity transmission line would be necessary for OG&E and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states. The Company has also previously committed to the Southwest Power Pool (“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 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.

 

Overview

 

Summary of Operating Results

 

Quarter ended September 30, 2007 as compared to quarter ended September 30, 2006

 

The Company reported net income of approximately $126.8 million, or $1.37 per diluted share, during the three months ended September 30, 2007, as compared to approximately $121.4 million, or $1.31 per diluted share, during the three months ended September 30, 2006. The increase in net income of approximately $5.4 million, or $0.06 per diluted share, during the three months ended September 30, 2007 as compared to the same period in 2006 was due to:

 

 

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Enogex’s net income for the three months ended September 30, 2007 of approximately $20.4 million included a loss of approximately $3.0 million at OGE Energy Resources, Inc. (“OERI”) resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2007. Also, for the three months ended September 30, 2007, OERI recorded losses of approximately $0.9 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 are expected to be realized during the first quarter of 2008.

 

Nine months ended September 30, 2007 as compared to nine months ended September 30, 2006

 

The Company reported net income of approximately $206.6 million, or $2.24 per diluted share, during the nine months ended September 30, 2007, as compared to approximately $240.0 million, or $2.61 per diluted share, during the nine months ended September 30, 2006. The decrease in net income of approximately $33.4 million, or $0.37 per diluted share, during the nine months ended September 30, 2007 as compared to the same period in 2006 was due to:

 

 

Enogex’s net income for the nine months ended September 30, 2007 of approximately $64.0 million included a loss of approximately $2.0 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2007. Also, for the nine months ended September 30, 2007, OERI recorded losses of approximately $2.2 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 are expected to be realized during the first quarter of 2008.

 

2007 Outlook

 

The Company’s 2007 earnings guidance remains $213 million to $231 million of income from continuing operations, or $2.30 to $2.50 per diluted share, as shown in the table below. The Company has assumed approximately 92.5 million average diluted shares outstanding, cash flow from operations of between $414 million and $432 million and an effective tax rate of 33.3 percent.

 

 

Key assumptions for 2007 are:

 

As shown above, OG&E’s earnings guidance is $138 million to $147 million, or $1.49 to $1.59 per diluted share of the Company’s common stock. Key factors and assumptions underlying this guidance include:

 

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OG&E

 

 

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 $77 million to $85 million, or $0.83 to $0.92 per diluted share of the Company’s common stock. Key factors and assumptions underlying this guidance include:

 

 

 

 

 

 

 

 

 

 

 

 

Enogex expects to continue to evaluate the strategic fit and financial performance of each of its assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been included in the 2007 earnings guidance. This guidance also does not include any impact from the proposed Offering of limited partnership interests in the Partnership discussed above or any transactions related to such Offering, including the payment of any make whole premium associated with the Enogex long-term debt expected to be refinanced in connection with the Offering.

 

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Holding Company

 

For 2007, the Company’s earnings guidance for the holding company reflects a loss of $1 million to $2 million, or $0.01 to $0.02 per diluted share.

 

Results of Operations

 

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the three and nine months ended September 30, 2007 as compared to the same period in 2006 and the Company’s consolidated financial position at September 30, 2007. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

 

 

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed 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 Condensed Consolidated Financial Statements.

 

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OG&E

(A) Megawatt-hour.

(B) Kilowatt-hour.

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

 

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Quarter ended September 30, 2007 as compared to quarter ended September 30, 2006

 

OG&E’s operating income decreased approximately $16.8 million during the three months ended September 30, 2007 as compared to the same period in 2006 primarily due to a lower gross margin, which is operating revenues less cost of goods sold, higher operating expenses and higher depreciation expense.

 

Gross Margin

 

Gross margin was approximately $306.3 million during the three months ended September 30, 2007 as compared to approximately $315.1 million during the same period in 2006, a decrease of approximately $8.8 million, or 2.8 percent. The gross margin decreased primarily due to:

 

 

These decreases 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 $231.2 million during the three months ended September 30, 2007 as compared to approximately $225.5 million during the same period in 2006, an increase of approximately $5.7 million, or 2.5 percent, primarily due to increased natural gas generation in 2007 partially offset by lower natural gas prices and decreased coal generation in 2007. 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. Purchased power costs were approximately $95.2 million during the three months ended September 30, 2007 as compared to approximately $68.1 million during the same period in 2006, an increase of approximately $27.1 million, or 39.8 percent. This increase was primarily due to OG&E’s entrance into the energy imbalance service market on February 1, 2007 (see Note 13 of Notes to Condensed 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 $78.5 million during the three months ended September 30, 2007 as compared to approximately $74.1 million during the same period in 2006, an increase of approximately $4.4 million, or 5.9 percent. The increase in other operation and maintenance expenses was primarily due to:

 

 

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Depreciation expense was approximately $35.3 million during the three months ended September 30, 2007 as compared to approximately $32.5 million during the same period on 2006, an increase of approximately $2.8 million, or 8.6 percent, primarily due to the Centennial wind farm being placed in service during January 2007.

 

Additional Information

 

Allowance for equity funds used during construction. Allowance for equity funds used during construction was approximately $0.3 million during the three months ended September 30, 2007 as compared to approximately $2.3 million during the same period in 2006, a decrease of approximately $2.0 million, or 86.7 percent, 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 $1.2 million during the three months ended September 30, 2007 as compared to approximately $0.2 million during the same period in 2006, an increase of approximately $1.0 million, primarily due to an increase in income related to the guaranteed flat bill tariff during 2007 resulting from more customers participating in this plan.

 

Interest Expense. Interest expense was approximately $16.0 million during the three months ended September 30, 2007 as compared to approximately $21.0 million during the same period in 2006, a decrease of approximately $5.0 million, or 23.8 percent. The decrease in interest expense was primarily due to decreased interest of approximately $7.3 million due to the one-time recognition of interest expense and related amortization of interest expense associated with a certain water storage agreement in 2006. This decrease in interest expense was partially offset by:

 

 

Income Tax Expense. Income tax expense was approximately $51.9 million during the three months ended September 30, 2007 as compared to approximately $69.6 million during the same period in 2006, a decrease of approximately $17.7 million, or 25.4 percent, primarily due to lower pre-tax income for OG&E and renewable energy tax credits for which OG&E became eligible in 2007 on the wind power production from OG&E’s Centennial wind farm.

 

Nine months ended September 30, 2007 as compared to nine months ended September 30, 2006

 

OG&E’s operating income decreased approximately $32.8 million during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a lower gross margin, higher depreciation expense and higher taxes other than income partially offset by lower operating expenses.

 

Gross Margin

 

Gross margin was approximately $639.7 million during the nine months ended September 30, 2007 as compared to approximately $666.5 million during the same period in 2006, a decrease of approximately $26.8 million, or 4.0 percent. The gross margin decreased primarily due to:

 

 

 

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These decreases in the gross margin were partially offset by:

 

 

Fuel expense was approximately $568.0 million during the nine months ended September 30, 2007 as compared to approximately $585.5 million during the same period in 2006, a decrease of approximately $17.5 million, or 3.0 percent, primarily due to decreased natural gas generation in 2007 partially offset by 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. Purchased power costs were approximately $195.6 million during the nine months ended September 30, 2007 as compared to approximately $175.4 million during the same period in 2006, an increase of approximately $20.2 million, or 11.5 percent. This increase was primarily due to OG&E’s entrance into the energy imbalance service market on February 1, 2007 (see Note 13 of Notes to Condensed Consolidated Financial Statements for a further discussion).

 

Operating Income

 

Other operation and maintenance expenses were approximately $230.8 million during the nine months ended September 30, 2007 as compared to approximately $233.8 million during the same period in 2006, a decrease of approximately $3.0 million, or 1.3 percent. The decrease in other operation and maintenance expenses was primarily due to:

 

 

These decreases in other operating and maintenance expenses were partially offset by higher outside services expense of approximately $3.4 million.

 

Depreciation expense was approximately $105.3 million during the nine months ended September 30, 2007 as compared to approximately $98.8 million during the same period in 2006, an increase of approximately $6.5 million, or 6.6 percent, primarily due to the Centennial wind farm being placed in service during January 2007.

 

Taxes other than income were approximately $42.3 million during the nine months ended September 30, 2007 as compared to approximately $39.8 million in 2006, an increase of approximately $2.5 million, or 6.3 percent, primarily due to increased ad valorem tax accruals.

 

Additional Information

 

Interest Income. There was no interest income during the nine months ended September 30, 2007 as compared to approximately $1.7 million during the same period in 2006. The decrease was primarily due to interest income earned on fuel under recoveries during the nine months ended September 30, 2006 while there was a fuel over recovery balance during the same period in 2007.

 

Allowance for equity funds used during construction. Allowance for equity funds used during construction was approximately $0.7 million during the nine months ended September 30, 2007 as compared to approximately $2.5 million during the same period in 2006, a decrease of approximately $1.8 million, or 72.0 percent, primarily due to construction costs for the Centennial wind farm that exceeded the average daily short-term borrowings in 2006.

 

Other Income. Other income was approximately $3.9 million during the nine months ended September 30, 2007. There was no other income during the same period in 2006. The increase in other income was primarily due to an increase in income related to the guaranteed flat bill tariff during 2007 resulting from more customers participating in this plan.

 

Other Expense. Other expense was approximately $5.1 million during the nine months ended September 30, 2007 as compared to approximately $9.0 million during the same period in 2006, a decrease of approximately $3.9 million, or 43.3 percent, primarily due to a loss on the retirement of fixed assets in 2006.

 

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Interest Expense. Interest expense was approximately $48.1 million during the nine months ended September 30, 2007 as compared to approximately $46.2 million during the same period in 2006, an increase of approximately $1.9 million, or 4.1 percent. The increase in interest expense was primarily due to:

 

 

These increases in net interest expense were partially offset by decreased interest of approximately $7.0 million due to the one-time recognition of interest expense and related amortization of interest expense associated with a certain water storage agreement in 2006.

 

Income Tax Expense. Income tax expense was approximately $66.7 million during the nine months ended September 30, 2007 as compared to approximately $92.8 million during the same period in 2006, a decrease of approximately $26.1 million, or 28.1 percent, primarily due to lower pre-tax income for OG&E and renewable energy tax credits for which OG&E became eligible in 2007 on the wind power production from OG&E’s Centennial wind farm.

 

Enogex – Continuing Operations

 

 

 

 

 

 

 

 

 

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Statistical Data – Continuing Operations

(A) Includes wells behind central receipt points (as reported to management by third parties).

(B) Trillion British thermal units per day.

(C) Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.

 

Quarter ended September 30, 2007 as compared to quarter ended September 30, 2006

 

Enogex’s operating income increased approximately $14.3 million during the three months ended September 30, 2007 as compared to the same period in 2006 primarily due to a higher gross margin in each of Enogex’s segments, which was partially offset by higher operating expenses and higher depreciation expense.

 

Gas imbalances affect Enogex’s results of operations. Gas imbalances occur when the actual amounts of natural gas delivered from or received by Enogex’s pipeline system differ from the amounts scheduled to be delivered or received. Imbalances due to shippers by Enogex are shown on Enogex’s consolidated balance sheets as a liability and imbalances due to Enogex from shippers are shown as an asset on Enogex’s consolidated balance sheets. Exclusive of changes in the price of natural gas, increases in the amount of imbalances shown as an asset, or decreases in the amount of imbalances shown as a liability, on Enogex’s consolidated balance sheets increase Enogex’s gross margin, while decreases in the amount of imbalances shown as an asset, or increases in the amount of imbalances shown as a liability, on Enogex’s consolidated balance sheets decrease gross margin.

 

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Gross Margin

 

Enogex’s consolidated gross margin increased approximately $18.9 million during the three months ended September 30, 2007 as compared to the same period in 2006. The increase resulted from higher gross margins in the transportation and storage business ($12.9 million), the gathering and processing business ($4.5 million) and the marketing business ($1.5 million).

 

The transportation and storage business contributed approximately $37.8 million of Enogex’s consolidated gross margin during the three months ended September 30, 2007 as compared to approximately $24.9 million during the same period in 2006, an increase of approximately $12.9 million, or 51.8 percent. The gross margin increased primarily due to:

 

 

 

 

The gathering and processing business contributed approximately $46.2 million of Enogex’s consolidated gross margin during the three months ended September 30, 2007 as compared to approximately $41.7 million during the same period in 2006, an increase of approximately $4.5 million, or 10.8 percent. The gathering and processing gross margin increased primarily due to:

 

 

These increases in the gathering and processing gross margin were partially offset by a reduction in fuel recoveries during the three months ended September 30, 2007, which decreased the gross margin by approximately $2.9 million.

 

The marketing business contributed approximately $1.7 million of Enogex’s consolidated gross margin during the three months ended September 30, 2007 as compared to approximately $0.2 million during the same period in 2006, an increase of approximately $1.5 million. The gross margin increased primarily due to:

 

 

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Operating Income

 

As shown above, Enogex’s operating income is calculated by subtracting from gross margin the following four items: (i) other operation and maintenance expenses, (ii) depreciation expense, (iii) impairment of assets and (iv) taxes other than income. Enogex’s consolidated operating income for the three months ended September 30, 2007 was approximately $39.8 million, a $14.3 million increase from its consolidated operating income for the three months ended September 30, 2006. The increase was attributable primarily to the $18.9 million increase described above in consolidated gross margin, as the aggregate of other operation and maintenance expenses, depreciation expense, impairment of assets and taxes other than income was only approximately $4.6 million higher during the three months ended September 30, 2007 as compared to the same period in 2006. The slight variances in depreciation expense and in taxes other than income on both a consolidated basis and by segment reflect differing levels of depreciable plant in service and a slight decrease in property taxes. The $3.9 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to higher salaries, wages and other employee benefits due to higher incentive compensation and hiring additional employees and higher materials and supplies expenses related to work performed to maintain the integrity and safety of Enogex’s pipeline.

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $1.4 million, or 15.1 percent, higher during the three months ended September 30, 2007 as compared to the same period in 2006 primarily due to higher salaries, wages and other employee benefits expense of approximately $1.2 million primarily due to higher incentive compensation and hiring additional employees to support business growth and higher materials and supplies expense of approximately $0.5 million related to work performed to maintain the integrity and safety of Enogex’s pipeline.

 

Other operation and maintenance expenses for the gathering and processing business increased approximately $3.1 million, or 20.8 percent, during the three months ended September 30, 2007 as compared to the same period in 2006. The increase was primarily due to higher allocations from Enogex of approximately $1.7 million primarily due to increased costs in 2007 and higher salaries, wages and other employee benefits expense of approximately $0.4 million primarily due to higher incentive compensation and hiring additional employees to support business growth.

 

Other operation and maintenance expenses for the marketing business were approximately $0.6 million, or 28.6 percent, lower during the three months ended September 30, 2007 as compared to the same period in 2006. The decrease was primarily due to a fee the marketing business began charging the Enogex parent company in 2007 related to hedging activities partially offset by higher allocations from Enogex primarily due to increased costs in 2007.

 

Enogex Consolidated Information

 

Income Tax Expense. Enogex consolidated income tax expense was approximately $13.3 million during the three months ended September 30, 2007 as compared to approximately $8.0 million during the same period in 2006, an increase of approximately $5.3 million, or 66.3 percent, primarily due to higher pre-tax income.

 

Non-Recurring and Timing Items. For the three months ended September 30, 2007, Enogex’s consolidated net income of approximately $20.4 million included a loss of approximately $3.0 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The

 

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offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2007. Also, for the three months ended September 30, 2007, OERI recorded losses of approximately $0.9 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 are expected to be realized during the first quarter of 2008. During the three months ended September 30, 2007, Enogex had no significant items that it does not consider to be reflective of its ongoing performance.

 

For the three months ended September 30, 2006, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “Enogex—Discontinued Operations,” of approximately $12.1 million included a gain of less than approximately $0.1 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2006. The gains from physical utilization of the transportation capacity were realized during the remainder of 2006. Also, at September 30, 2006, OERI recorded a gain of approximately $3.9 million resulting from recording economic storage hedges at market value. The offsetting reductions in gains from the sale of withdrawals from inventory were realized during the remainder of 2006 and through the first quarter of 2007. Also, during the three months ended September 30, 2006, Enogex had a decrease in net income of approximately $0.8 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These decreases in consolidated net income include:

 

 

Nine months ended September 30, 2007 as compared to nine months ended September 30, 2006

 

Enogex operating income increased approximately $23.4 million during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a higher gross margin in each of Enogex’s segments, which was partially offset by higher operating expenses and higher depreciation expense.

 

Gross Margin

 

Enogex’s consolidated gross margin increased approximately $33.8 million during the nine months ended September 30, 2007 as compared to the same period in 2006. The increase resulted from a higher gross margin in the transportation and storage business ($15.0 million), the gathering and processing business ($6.7 million) and the marketing business ($12.1 million).

 

The transportation and storage business contributed approximately $108.0 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $93.0 million during the same period in 2006, an increase of approximately $15.0 million, or 16.1 percent. The gross margin increased primarily due to:

 

 

 

 

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The gathering and processing business contributed approximately $128.7 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $122.0 million during the same period in 2006, an increase of approximately $6.7 million, or 5.5 percent. The gathering and processing gross margin increased primarily due to:

 

 

 

 

The marketing business contributed approximately $18.7 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $6.6 million during the same period in 2006, an increase of approximately $12.1 million. The gross margin increased primarily due to:

 

 

 

 

 

Enogex’s consolidated operating income for the nine months ended September 30, 2007 was approximately $120.6 million, a $23.4 million increase from its consolidated operating income for the nine months ended September 30, 2006. The increase was attributable primarily to the $33.8 million increase described above in consolidated gross margin, as

 

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the aggregate of other operation and maintenance expenses, depreciation expense, impairment of assets and taxes other than income was only approximately $10.4 million higher during the nine months ended September 30, 2007 as compared to the same period in 2006. The slight variances in depreciation expense and in taxes other than income on both a consolidated basis and by segment reflect differing levels of depreciable plant in service and a slight decrease in property taxes. The $8.1 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to higher salaries, wages and other employee benefits due to higher incentive compensation and hiring additional employees and a sales and use tax refund received in the prior year.

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $4.0 million, or 13.8 percent, higher during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to higher salaries, wages and other employee benefits expense of approximately $3.7 million primarily due to higher incentive compensation and hiring additional employees to support business growth.

 

Other operation and maintenance expenses for the gathering and processing business increased approximately $6.8 million, or 15.4 percent, during the nine months ended September 30, 2007 as compared to the same period in 2006. This increase was primarily due to higher allocations from Enogex of approximately $3.1 million primarily due to increased costs in 2007 and a sales and use tax refund of approximately $2.0 million received in May 2006 related to activity in prior years with no corresponding item in 2007.

 

Other operation and maintenance expenses for the marketing business were approximately $2.7 million, or 37.5 percent, lower during the nine months ended September 30, 2007 as compared to the same period in 2006. The decrease was primarily due to a fee the marketing business began charging the Enogex parent company in 2007 related to hedging activities, lower salaries, wages and benefits due to a decrease in the number of marketing employees compared to 2006 partially offset by higher allocations from Enogex primarily due to increased costs in 2007.

 

 

Interest Income. Enogex consolidated interest income was approximately $7.0 million during the nine months ended September 30, 2007 as compared to approximately $8.7 million during the same period in 2006, a decrease of approximately $1.7 million, or 19.5 percent, primarily due to interest income earned on cash investments from the cash proceeds from the sale of certain gas gathering assets in the Kinta, Oklahoma area (the “Kinta Assets”) in May 2006.

 

Other Income. Enogex consolidated other income was approximately $0.8 million during the nine months ended September 30, 2007 as compared to approximately $6.4 million during the same period in 2006, a decrease of approximately $5.6 million, or 87.5 percent, primarily due to a litigation settlement of approximately $5.2 million in 2006 and a pre-tax gain of approximately $0.5 million in the first quarter of 2006 from the sale of small gathering sections of Enogex’s pipeline.

 

Income Tax Expense. Enogex consolidated income tax expense was approximately $40.0 million during the nine months ended September 30, 2007 as compared to approximately $33.9 million during the same period in 2006, an increase of approximately $6.1 million, or 18.0 percent, primarily due to higher pre-tax income.

 

Non-Recurring and Timing Items. For the nine months ended September 30, 2007, Enogex’s consolidated net income of approximately $64.0 million included a loss of approximately $2.0 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2007. Also, for the nine months ended September 30, 2007, OERI recorded losses of approximately $2.2 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 are expected to be realized during the first quarter of 2008. During the nine months ended September 30, 2007, Enogex had no significant items that it does not consider to be reflective of its ongoing performance.

 

For the nine months ended September 30, 2006, Enogex’s consolidated net income, including the discontinued operations discussed below under the caption “Enogex—Discontinued Operations,” of approximately $90.4  million included a loss of less than approximately $0.1 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2006. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2006. Also, at September 30, 2006, OERI recorded a gain of approximately $6.2 million resulting from recording economic storage hedges at market value. The offsetting reductions in gains from the sale of withdrawals from inventory were realized during the remainder of 2006 and through the first quarter of 2007. Also, during the nine months ended September 30, 2006, Enogex had an increase in net

 

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income of approximately $40.6 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These increases in consolidated net income include:

 

 

Enogex – Discontinued Operations

 

In March 2006, Enogex announced that its wholly owned subsidiary, Enogex Gas Gathering, L.L.C., had entered into an agreement to sell the Kinta Assets. These assets included in the transaction were approximately 568 miles of gas gathering pipeline and 22 compressor units with current volumes of approximately 145 million cubic feet per day, all in eastern Oklahoma. The sale price was approximately $93 million. This transaction closed on May 1, 2006 and Enogex recorded an after tax gain of approximately $34.1 million during the second quarter of 2006. The proceeds from the sale, were used, among other things, to reduce short-term debt levels and fund capital expenditures.

 

As a result of this sale transaction, the Kinta Assets, which were part of the natural gas transportation and storage and gathering and processing segments, have been reported as discontinued operations for the three and nine months ended September 30, 2006 in the Condensed Consolidated Financial Statements. Results for these discontinued operations are summarized and discussed below.

 

 

Following the sale of the Kinta Assets in May 2006, no operations of the Kinta Assets are reflected in the Condensed Consolidated Financial Statements.

 

Financial Condition

 

The balance of Cash and Cash Equivalents was approximately $2.0 million and $47.9 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $45.9 million, or 95.8 percent, primarily due to ad valorem tax payments, dividend payments, pension plan funding and daily operational needs of the Company.

 

The balance of current Price Risk Management assets was approximately $9.0 million and $38.3 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $29.3 million, or 76.5 percent. The decrease was primarily due to OERI’s physical purchases and sales activity recorded at December 31, 2006 being realized during the first nine months of 2007 partially offset by new physical activity and an increase in the value of existing activity. The decrease was also related to transportation hedges recorded at December 31, 2006 being realized during the first nine months of 2007 partially offset by new Cheyenne Plains and other transportation hedges.

 

The balance of Construction Work in Progress was approximately $137.8 million and $191.1 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $53.3 million, or 27.9 percent, primarily due to OG&E’s Centennial wind farm being placed in service during January 2007 partially offset by various distribution and transmission projects at OG&E and the construction of a processing plant and gathering system expansion projects at Enogex.

 

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The balance of Other Deferred Charges and Other Assets was approximately $39.9 million and $23.1 million at September 30, 2007 and December 31, 2006, respectively, an increase of approximately $16.8 million, or 72.7 percent, primarily due to the deferral of capitalized costs associated with the cancelled Red Rock power plant project.

 

The balance of Short-Term Debt was approximately $158.9 million at September 30, 2007. There was no short-term debt outstanding at December 31, 2006. The increase was primarily due to borrowings to fund ad valorem tax payments, pension plan funding, dividend payments and daily operational needs of the Company.

 

The balance of Accounts Payable was approximately $229.6 million and $295.0 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $65.4 million, or 22.2 percent, primarily due to a decrease in gas purchases and market prices at Enogex.

 

The balance of Accrued Taxes was approximately $85.9 million and $57.0 million at September 30, 2007 and December 31, 2006, respectively, an increase of approximately $28.9 million, or 50.7 percent, primarily due to an increase in the Company’s estimated income tax liability and the timing of payments and accruals of ad valorem taxes.

 

The balance of Fuel Clause Over Recoveries was approximately $35.1 million and $96.3 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $61.2 million, or 63.6 percent. The decrease in fuel clause over recoveries was due to the fact that the amount billed to the Company’s customers during the nine months ended September 30, 2007 was less than OG&E’s cost of fuel. OG&E fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel cost in periods of rising prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under or over recovery.

 

The balance of Accrued Pension and Benefit Obligations was approximately $198.8 million and $231.3 million at September 30, 2007 and December 31, 2007, respectively, a decrease of approximately $32.5 million, or 14.1 percent, primarily due to pension plan contributions during 2007.

 

The balance of Accrued Removal Obligations, Net was approximately $141.7 million and $125.5 million at September 30, 2007 and December 31, 2007, respectively, an increase of approximately $16.2 million, or 12.9 percent, primarily due to depreciation on cost of removal and highway billing projects.

 

Off-Balance Sheet Arrangements

 

Except as discussed below, there have been no significant changes in the Company’s off-balance sheet arrangements from those discussed in the Company’s 2006 Form 10-K.

 

Heat Pump Loans

 

In December 2002, OG&E sold approximately $8.5 million of its heat pump loans in a securitization transaction through OGE Consumer Loan 2002, LLC. In August 2007, OG&E repurchased the outstanding heat pump loan balance of approximately $0.6 million. There was no gain or loss associated with the repurchase of the heat pump loans.

 

Liquidity and Capital Requirements

 

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and at 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 internally generated funds, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

 

Cash Flows

 

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The reduction of approximately $138.8 million in net cash provided from operating activities during the nine months ended September 30, 2007 as compared to the same period in 2006 was primarily related to lower fuel recoveries from OG&E customers and changes to other working capital. The increase in net cash used in investing activities of approximately $38.9 million during the nine months ended September 30, 2007 as compared to the same period in 2006 related to higher levels of capital expenditures. The increase in net cash provided from financing activities of approximately $153.8 million during the nine months ended September 30, 2007 as compared to the same period in 2006 related primarily to higher levels of short-term debt partially offset by reduced amounts related to the issuance of long-term debt.

 

Future Capital Requirements

 

Capital Expenditures

 

The Company’s current 2007 to 2012 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 for 2007 through 2012 are approximately $532.1 million, $558.3 million, $599.7 million, $671.5 million, $657.0 million and $674.3 million, respectively. These capital expenditures exclude any expenditures related to the Company’s wind power initiative discussed earlier.

 

Pension and Postretirement Benefit Plans

 

In the third quarter of 2007, the Company contributed approximately $10 million to its pension plan for a total contribution of $50 million to its pension plan during 2007. No additional contributions are expected in 2007.

 

In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the first nine months of 2007 as compared to the first nine months of recent years, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement in 2007. As a result, and based in part on the Company’s historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, the Company currently expects that it could be required to record a pension settlement charge for 2007 of between $12.2 million and $13.5 million in the fourth quarter of 2007, of which approximately $2.4 million would be recorded as an expense and the remaining balance would be recorded as capital and as a regulatory asset. Whether the Company will be required to take a pension settlement charge for 2007 will depend on numerous factors, including the amount of lump sum payments owed to employees who elect to retire during the balance of 2007 and the investment performance of the Company’s pension plan during 2007. A pension settlement charge, if incurred, would not require a cash outlay by the Company and would not increase the Company’s total pension expense over time, as the charge would be an acceleration of costs that otherwise would be recognized as pension expense in future periods.

 

Adoption of FIN No. 48

 

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized approximately a $3.8 million increase in the accrued interest liability, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility (see Note 6 of Notes to Consolidated Financial Statements for a further discussion).

 

Future Sources of Financing

 

Management expects that internally generated funds, 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.

 

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Issuance of Long-Term Debt

 

OG&E expects to issue long-term debt during the fourth quarter of 2007 to fund capital expenditures and for working capital purposes.

 

Short-Term Debt

 

Short-term borrowings generally are used to meet working capital requirements. In December 2006, the Company and OG&E increased their aggregate available borrowing capacity under their revolving credit agreements from $750.0 million to $1.0 billion, $600 million for the Company and $400 million for OG&E. At September 30, 2007, the Company had approximately $158.3 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. See Note 9 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

 

As discussed above, in May 2007, the Company formed the Partnership as part of its strategy to further develop Enogex’s natural gas midstream assets and operations and, the Partnership has filed its initial registration statement for the proposed Offering.

 

It is currently expected that at the closing of the Offering, Enogex will enter into a $250 million credit facility for working capital, capital expenditures and other corporate purposes, including acquisitions. Also as part of the Offering, Enogex currently expects to refinance its $400 million 8.125% senior notes due 2010, including the payment of a make-whole premium of approximately $30.1 million, with a combination of $300 million of new debt (which may include borrowings from the Company) and approximately $130.1 million of the proceeds of the Offering that the Partnership expects to contribute to Enogex for the anticipated repayment of that debt.

 

Critical Accounting Policies and Estimates

 

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material affect on the Company’s Condensed Consolidated Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts. The selection, application and disclosure of the Company’s critical accounting estimates have been discussed with the Company’s Audit Committee and are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s 2006 Form 10-K.

 

Accounting Pronouncements

 

See Notes 2, 3 and 6 of Notes to Condensed Consolidated Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

 

Electric Competition; Regulation

 

OG&E and Enogex 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 are being proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas were postponed in 2001, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on the Company due to possible impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring also could have a significant impact on the Company’s consolidated financial position, results of operations and cash flows. The Company cannot predict when it will be subject to changes in legislation or regulation, nor can it predict the impact of these changes on the Company’s consolidated financial position, results of

 

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operations or cash flows. The Company believes that the prices for electricity and the quality and reliability of the Company’s service currently place us in a position to compete effectively in the energy market. OG&E is also subject to competition in various degrees from state-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. OG&E has a franchise to serve in more than 270 towns and cities throughout its service territory.

 

Commitments and Contingencies

 

Except as disclosed otherwise in this Form 10-Q, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of 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. See Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q and Notes 17 and 18 of Notes to Consolidated Financial Statements and Item 3 of Part I of the 2006 Form 10-K for a discussion of the Company’s commitments and contingencies.

 

 

Except as set  forth below, the  market risks  set forth in Part II, Item  7A of the Company’s 2006  Form
10-K appropriately represent, in all material respects, the market risks affecting the Company.

 

Commodity Price Risk

 

The market risks inherent in the Company’s market risk sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the commodity prices to which the Company is exposed. These market risks can be classified as trading, which includes transactions that are entered into voluntarily to capture subsequent changes in commodity prices, or non-trading, which includes the exposure some of the Company’s assets have to commodity prices.

 

Trading Activities

 

The trading activities are conducted throughout the year subject to daily and monthly trading stop loss limits set by the Risk Oversight Committee. Those trading stop loss limits currently are $2.5 million. The daily loss exposure from trading activities is measured primarily using value-at-risk (“VaR”), which estimates the potential losses the trading activities could incur over a specified time horizon and confidence level. The VaR limit defined and set by the Risk Oversight Committee for the Company’s trading activities, assuming a 95 percent confidence level, currently is $1.5 million. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company’s operating income.

 

A sensitivity analysis has been prepared to estimate the Company’s exposure to market risk created by trading activities. The value of trading positions is a summation of the fair values for each net commodity position based upon quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in quoted market prices over the next 12 months. The result of this analysis, which may differ from actual results, is as follows for September 30, 2007.

 

 

Non-Trading Activities

 

The prices of natural gas, natural gas liquids and natural gas liquids processing spreads are subject to fluctuations resulting from changes in supply and demand. The changes in these prices have a direct effect on the compensation the Company receives for operating some of its assets. To partially reduce non-trading commodity price risk, the Company hedges, through the utilization of derivatives and other forward transactions, the effects these market fluctuations have on the operating income. Because the commodities covered by these hedges are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

 

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A sensitivity analysis has been prepared to estimate the Company’s exposure to the market risk of the Company’s non-trading activities. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. Quoted market prices are not available for all of the Company’s non-trading positions, therefore, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forecast prices.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The result of this analysis, which may differ from actual results, is as follows for September 30, 2007.

 

 

The Company may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Normal purchases and normal sales contracts are not recorded in Price Risk Management assets or liabilities in the Condensed Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales to (i) commodity contracts for the purchase and sale of natural gas; (ii) commodity contracts for the sale of natural gas liquids produced by its subsidiary, Enogex Products Corporation; (iii) electric power contracts by OG&E; and (iv) fuel procurement by OG&E.

 

 

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

 

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

 

PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

Reference is made to Part I, Item 3 of the Company’s 2006 Form 10-K for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

 

1.           United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with 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 United States Government, alleges:  (i) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of

 

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gas processing. Grynberg seeks the following damages:  (a) additional royalties which he claims should have been paid to the United States Government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

 

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

 

The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multi-District 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 United States District Court for the District of Wyoming.

 

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of 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 for other legal costs on December 18, 2006. The defendants filed motions for attorneys’ fees regarding issues of liability and Rule 11 motions on January 8, 2007. 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 an appellants’ opening brief on July 31, 2007. The appellees’ consolidated response brief is due on November 21, 2007. At this time, oral arguments are preliminarily scheduled during the week of May 12, 2008. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

 

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

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005.

 

In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

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

 

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

 

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3.           Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II). On May 12, 2003, the plaintiffs (same as those in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the amended petition of the Price I case. The plaintiffs allege that the defendants mismeasured the British thermal unit content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005.

 

In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

 

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

 

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

 

4.          In Ronald A. Katz Technology Licensing, L.P. v. OGE Energy Corp., et al. (United States W.D. Okla. 2007) (Civil Action No. 5:07-CV-00650-C), Ronald A. Katz Technology Licensing, L.P. (“RAKTL”) sued the Company and OG&E on June 7, 2007 for patent infringement. RAKTL alleges that OG&E, by operating automated telephone systems that allow OG&E’s customers to access account information, sign-up for new service, transfer service, arrange for an installment payment plan, make a payment on an account, request a duplicate bill, report an electricity outage, and perform various other functions, has infringed 13 of RAKTL’s patents and continues to infringe four of RAKTL’s patents. RAKTL seeks unspecified damages resulting from OG&E’s alleged infringement, including treble damages, as well as a permanent injunction enjoining OG&E from continuing the alleged infringement. RAKTL has previously filed similar actions against numerous companies and these previously filed cases have been consolidated pursuant to MDL proceedings in the United States District Court for the Central District of California. The Judicial Panel on MDL issued a conditional transfer order on June 20, 2007, consolidating this case with the currently pending MDL proceedings, In re Katz Interactive Call Processing Patent Litigation Case No. MDL-1816. On July 31, 2007, the MDL Panel’s conditional transfer was filed in the United States District Court for the Central District of California. This filing affected the transfer of the Company’s case, pending before the United States District Court for the Western District of Oklahoma, to the United States District Court for the Central District of California. On August 15, 2007, the Western District of Oklahoma Court entered the order transferring the Company’s case to the Central District of California Court and the Oklahoma Court closed its file on same date. On September 12, 2007, RAKTL filed its reply to the counterclaims of the Company defendants in the Central District of California. On September 26, 2007, the United States District Court for the Central District of California issued its order for an initial conference which was held on October 30, 2007. While the Company cannot predict the outcome of this lawsuit at this time, the Company intends to vigorously defend this case and believes that its ultimate resolution will not be material to the Company’s consolidated financial position or results of operations.

 

Item 1A. Risk Factors.

 

Except as discussed below, there have been no significant changes in the Company’s risk factors from those discussed in the Company’s 2006 Form 10-K.

 

Due to the October 11, 2007 OCC order denying the request for pre-approval of the proposed Red Rock power plant project and the resulting termination of the project, the risk factor captioned “We may incur additional costs or delays in power plant construction and may not be able to recover our investment.” is modified as follows:

 

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 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

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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 of the denial for pre-approval, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At September 30, 2007, OG&E has incurred approximately $17.6 million of capitalized costs associated with the Red Rock power plant project. OG&E expects to file an application with the OCC requesting authorization to defer and propose a plan for recovery of approximately $15.4 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.

 

 

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

N/A – not applicable

 

 

As previously reported, Mr. Steven E. Moore, the Company’s Chairman of the Board and Chief Executive Officer (“CEO”), died on September 22, 2007, and immediately thereafter, Mr. Peter Delaney was appointed as Chairman of the Board, President and CEO to succeed Mr. Moore. Mr. Delaney previously had served as President and Chief Operating Officer of the Company. Also, as previously reported, Mr. Dan Harris, formerly the Company’s Senior Vice President – Unregulated Business, was appointed Senior Vice President and Chief Operating Officer of the Company. At the October 16, 2007 meeting of the Company’s Compensation Committee of its Board of Directors, effective as of October 1, 2007, and in recognition of the increased level of responsibilities, the annual salary of Mr. Delaney was increased from $531,000 to $775,000 and the annual salary of Mr. Harris was increased from $305,000 to $510,000. No change was made to other components of their compensation.

 

 

 

 

 

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SIGNATURE

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

November 1, 2007

 

 

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Exhibit 31.01

 

CERTIFICATIONS

 

I, Peter B. Delaney, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

 

 

 

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Exhibit 31.01

 

CERTIFICATIONS

 

I, James R. Hatfield, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: November 1, 2007

 

 

 

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Exhibit 32.01

 

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

In connection with the Quarterly Report of OGE Energy Corp. (the “Company”) on Form 10-Q for the period ended September 30, 2007, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

 

 

November 1, 2007

 

 

        

 

 

 

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