(Mark One)

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

        THE SECURITIES EXCHANGE ACT OF 1934

         For the quarterly period ended June 30, 2008

 

 

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

       THE SECURITIES EXCHANGE ACT OF 1934

        For the transition period from _____to_____

 

 

 

 

 

 

 

 

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OGE ENERGY CORP.

 

FORM 10-Q

 

FOR THE QUARTER ENDED JUNE 30, 2008

 

TABLE OF CONTENTS

 

 

 

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FORWARD-LOOKING STATEMENTS

 

Except for the historical statements contained herein, 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” in OGE Energy Corp.’s Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 Form 10-K”) and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

 

 

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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 CHANGES IN STOCKHOLDERS’ EQUITY

(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 CHANGES IN STOCKHOLDERS’ EQUITY (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)

 

1.	Summary of Significant Accounting Policies

 

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.

 

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

 

Effective April 1, 2008, Enogex Inc. converted from an Oklahoma corporation to a Delaware limited liability company. Also, effective April 1, 2008, Enogex Products Corporation, a wholly owned subsidiary of Enogex, converted from an Oklahoma corporation to an Oklahoma limited liability company.

 

In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture to construct high-capacity transmission line projects in western Oklahoma. The Company will own 50 percent of the joint venture.

 

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.

 

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 SEC. 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 June 30, 2008 and December 31, 2007, the results of its operations for the three and six months ended June 30, 2008 and 2007, and the results of its cash flows for the six months ended June 30, 2008 and 2007, have been included and are of a normal recurring nature except as otherwise disclosed.

 

Due to seasonal fluctuations and other factors, the operating results for the three and six months ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008 or for any future period. The

 

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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 2007 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.

 

The following table is a summary of OG&E’s regulatory assets and liabilities at:

 

 

In June 2008, OG&E proposed a plan to the OCC designed to ease the financial burden on its customers of higher summer electric bills resulting from near-record high natural gas prices. OG&E proposed that it would recover only 50 percent of specified fuel costs during the hot summer months while delaying recovery of the remaining amount until the milder months of fall and early winter. OG&E’s plan, which was implemented July 1, 2008, helps reduce the near-term impact on its customers of higher fuel prices. Customers will generally be paying less for fuel costs during the summer than they otherwise might have absent this plan, while bills received in the months of October through December will generally include higher fuel costs in order to recover deferred fuel costs. The unrecovered amount is included in Fuel Clause Under Recoveries in the table above.

 

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

 

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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Fuel Inventories

 

OG&E

 

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

 

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

 

The change in accounting for fuel inventory to the weighted-average cost method resulted in a higher fuel inventory balance of approximately $5.4 million at June 30, 2008. The change in accounting for fuel inventory to the weighted-average cost method did not impact the income statement for the three and six months ended June 30, 2008 as OG&E’s fuel costs are passed through to its customers through automatic fuel adjustment clauses.

 

Price Risk Management Assets and Liabilities

 

In accordance with 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,” 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 Condensed Consolidated Balance Sheets. 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 $54.6 million and $80.9 million, respectively, at June 30, 2008, and non-current Price Risk Management assets and liabilities would be approximately $58.1 million and $76.5 million, respectively, at June 30, 2008. 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 $10.0 million and $51.4 million, respectively, at December 31, 2007, and non-current Price Risk Management assets and liabilities would be approximately $2.6 million and $38.9 million, respectively, at December 31, 2007.

 

2.	Formation of OGE Enogex Partners L.P.

 

In May 2007, the Company formed the Partnership as part of its strategy to further develop Enogex’s natural gas midstream assets and operations. The Partnership has filed a registration statement with the SEC for a proposed initial public offering of its common units, representing limited partner interests in the Partnership (the “Offering”). At the date of this

 

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quarterly report, the registration statement relating to the Offering is not effective. In connection with the Offering, the Company is expected to contribute an approximate 25 percent membership interest in Enogex LLC to a wholly owned subsidiary of the Partnership that would serve as Enogex LLC’s managing member and would control its assets and operations. A wholly owned subsidiary of the Company will retain the remaining approximately 75 percent membership interest in Enogex. It is currently contemplated that at the completion of the Offering, the Company will indirectly own an approximate 77 percent limited partner interest and a two percent general partner interest in the Partnership.

 

The completion of the Offering is subject to numerous conditions and no assurances can be made that it will be successfully completed. The Company expects to continue to evaluate strategic alternatives for Enogex, including other transactions that the Company believes could provide long-term value to its shareowners and the proposed 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 June 30, 2008. 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.

 

3.	Accounting Pronouncements

 

In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets.” This FSP applies to recognized intangible assets that are accounted for pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets.” This FSP amends the factors that should be considered in developing renewal and extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. This FSP also seeks to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R), “Business Combinations,” and GAAP. A company’s own historical experience in renewing or extending similar arrangements should be considered in developing assumptions about renewal or extension used to determine the useful life of a recognized intangible asset. In the absence of such experience, assumptions that market participants would use about renewal or extension that are consistent with the highest and best use of the asset, adjusted for company specific factors, should be considered. The FSP requires that for recognized intangible assets, an entity should disclose information that enables the users of the financial statements to assess the extent to which the expected future cash flows associated with the asset are affected by the entity’s intent and/or ability to renew or extend the arrangement. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company will adopt this FSP effective January 1, 2009. The adoption of this FSP is not expected to have an impact on the Company’s consolidated financial position or results of operations as the Company does not currently have any intangible assets.

 

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with GAAP. SFAS No. 162 transfers the GAAP hierarchy from the American Institute of Certified Public Accountant’s (“AICPA”) Statement on Auditing Standards (“SAS”) No. 69, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles” to the FASB because entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 states the hierarchy of accounting sources that should be used in applying GAAP. If the accounting treatment for a specific transaction or event is not specified in the accounting guidance, an entity shall first consider accounting principles for similar transactions or events and then other accounting literature. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS No. 162 will not have an impact on the Company’s application of GAAP, consolidated financial position or results of operations.

 

4.	Fair Value Measurements

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in GAAP and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the

 

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guidance in footnote 3 of Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 generally are to be applied prospectively as of the beginning of the fiscal year in which it is initially applied. The Company adopted this new standard effective January 1, 2008.

 

The following table is a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis in accordance with SFAS No. 157.

 

 

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

 

Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. An example of instruments that may be classified as Level 1 includes futures transactions for energy commodities traded on the New York Mercantile Exchange (“NYMEX”).

 

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. An example of instruments that may be classified as Level 2 includes energy commodity purchase or sales transactions in a market such that the pricing is closely related to the NYMEX pricing.

 

Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available. Unobservable inputs shall reflect the reporting entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions. An example of instruments that may be classified as Level 3 includes energy commodity purchase or sales transactions of a longer duration or in an inactive market or the valuation of asset retirement obligations such that there are no closely related markets in which quoted prices are available.

 

 

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The following table is a reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at June 30, 2008.

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

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Gains and losses (realized and unrealized) included in earnings for the three and six months ended June 30, 2008 attributable to the change in unrealized gains or losses relating to assets and liabilities held at June 30, 2008, if any, are reported in operating revenues.

 

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, which have significantly changed since December 31, 2007.

 

 

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

 

5.	Stock-Based Compensation

 

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

 

The Company recorded compensation expense of approximately $1.8 million pre-tax ($1.1 million after tax, or $0.01 per basic and diluted share) and approximately $2.9 million pre-tax ($1.8 million after tax, or $0.02 per basic and diluted share), respectively, during the three and six months ended June 30, 2008 related to the Company’s share-based payments. The Company recorded compensation expense of approximately $0.6 million pre-tax ($0.4 million after tax, or less than $0.01 per basic and diluted share) and approximately $1.4 million pre-tax ($0.9 million after tax, or $0.01 per

 

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basic and diluted share), respectively, during the three and six months ended June 30, 2007 related to the Company’s share-based payments.

 

The Company issues new shares to satisfy stock option exercises. During the three and six months ended June 30, 2008, there were 322,700 shares and 491,964 shares, respectively, of new common stock issued pursuant to the Company’s Plans related to exercised stock options and payouts of earned performance units. The Company received approximately $7.4 million and $0.2 million during the three months ended June 30, 2008 and 2007, respectively, and approximately $7.6 million and $7.1 million during the six months ended June 30, 2008 and 2007, respectively, related to exercised stock options.

 

Registration Statement Filing

 

On June 19, 2008, the Company filed a Registration Statement on Form S-3 pursuant to which it may offer from time to time up to 6,000,000 shares of the Company’s common stock.

 

6.	Accumulated Other Comprehensive Income (Loss)

 

The components of accumulated other comprehensive loss at June 30, 2008 and December 31, 2007 are as follows:

 

 

7.	Income Taxes

 

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 2004. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its federal investment tax credits on a ratable basis throughout the year.  In addition, OG&E earns both federal and Oklahoma state tax credits associated with the production from its Centennial wind farm that further reduce the Company’s effective tax rate.

 

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.

 

 

 

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8.	Earnings Per Share

 

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

 

 

9.	Long-Term Debt

 

At June 30, 2008, the Company was in compliance with all of its debt agreements.

 

Optional Redemption of Long-Term Debt

 

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.

 

Registration Statement Filing

 

On June 5, 2008, OG&E filed a Registration Statement on Form S-3 pursuant to which it may offer from time to time up to $700 million of unsecured debt securities. OG&E expects to issue long-term debt later in 2008.

 

 

 

 

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10.	Short-Term Debt

 

The short-term debt balance was approximately $438.7 million and $295.8 million at June 30, 2008 and December 31, 2007, respectively. The following table shows the Company’s revolving credit agreements and available cash at June 30, 2008.

 

 

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. 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 would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit. Also, any downgrade below investment grade at OERI could require the Company to issue guarantees to support some of OERI’s 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.

 

11.	Retirement Plans and Postretirement Benefit Plans

 

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 132R,” which required an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements were effective for the year ended December 31, 2007 for the Company.

 

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The details of net periodic benefit cost of the pension plan, 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

(A) In addition to the $4.2 million and $6.1 million in SFAS No. 87, “Employers’ Accounting for Pensions,” net periodic benefit cost recognized during the three months ended June 30, 2008 and 2007, respectively, OG&E also recognized an expense of approximately $2.5 million and $1.3 million, respectively, related to the reversal of a portion of the regulatory asset identified as Deferred Pension Plan Expenses (see Note 1). In addition to the $8.4 million and $12.1 million in SFAS No. 87 net periodic benefit cost recognized during the six months ended June 30, 2008 and 2007, respectively, OG&E also recognized an expense of approximately $5.0 million and $2.4 million, respectively, related to the reversal of a portion of the regulatory asset identified as Deferred Pension Plan Expenses (see Note 1).

 

 

 

Pension Plan Funding

 

The Company previously disclosed in its 2007 Form 10-K that it may contribute up to $50 million to its pension plan during 2008. In the second quarter of 2008, the Company contributed approximately $40 million to its pension plan and currently expects to contribute an additional $10 million to its pension plan during the remainder of 2008. Any further contributions to the pension plan during 2008 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

 

12.	Report of Business Segments

The Company’s business is divided into four segments for financial reporting purposes. These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. As discussed in Note 1, on

 

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January 1, 2008, Enogex distributed the stock of OERI, which engages in the marketing of natural gas, to OGE Energy and, as a result, OERI is no longer a subsidiary of Enogex. Other Operations for the three and six months ended June 30, 2008 and 2007 primarily included the operations of the holding company. 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 six months ended June 30, 2008 and 2007. The results of the Company’s business segments have been restated for all prior periods presented to conform to the 2008 presentation.