(Mark One)

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

 

 

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

 

 

 

 

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  o  No  x

 

 

OGE ENERGY CORP.

 

FORM 10-Q

 

FOR THE QUARTER ENDED SEPTEMBER 30, 2008

 

TABLE OF CONTENTS

 

 

 

i

 

 

 

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:

 

 

 

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. 

 

 

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

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

 

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

 

 

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

 

 

 

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.

 

 

 

 

 

 

 

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

 

 

 

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

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

7

 

 

 

 

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

Organization

 

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. 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”). On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy.

 

In September 2008, OGE Energy and Energy Transfer Partners, L.P. (“ETP”) entered into an agreement to form a joint venture (“ETP Enogex Partners LLC”) combining Enogex’s midstream business with ETP’s interstate operations as well as its midstream operations in the Rocky Mountains. ETP Enogex Partners LLC will be jointly owned and managed by ETP and OGE Energy on a 50/50 basis. Based on the 50/50 ownership, with neither company having control, OGE Energy will present its interest using the equity method of accounting. For additional information regarding the joint venture, see Note 12. In light of the above proposed transaction as well as market conditions, OGE Enogex Partners, L.P., a partnership formed by the Company to further develop Enogex’s natural gas midstream assets and operations, which had previously filed a registration statement with the SEC for a proposed initial public offering of its common units, has determined not to proceed with the offering contemplated by the registration statement and to withdraw the registration statement.

 

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 September 30, 2008 and December 31, 2007, the results of its operations for the three and nine months ended September 30, 2008 and 2007, and the results of its cash flows for the nine months ended September 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 nine months ended September 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 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:

 

 

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.

 

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 Accounting Principles Board (“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 $5.2 million at September 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 nine months ended September 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 (“FIN”) 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 $15.5 million and $49.5 million, respectively, at September 30, 2008, and non-current Price Risk Management assets and liabilities would be approximately $35.3 million and $37.6 million, respectively, at September 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.

 

 

In September 2008, the FASB issued FASB Staff Position (“FSP”) No. 133-1 and FIN No. 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FIN No. 45; and clarification of the Effective Date of FASB Statement No. 161.” This FSP amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” by requiring sellers of credit derivatives to disclose information about their credit derivatives and hybrid instruments that have embedded credit derivatives to enable users of financial statements to assess their potential effect on the financial position, financial performance and cash flows of the entity. This FSP also amends FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” by requiring disclosure about the current status of the payment/performance risk of a guarantee. In addition, this FSP clarifies that the disclosures required by SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - An Amendment of

 

 

 

 

FASB Statement No. 133,” should be provided for any reporting period (annual or interim) beginning after November 15, 2008. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company will adopt this FSP effective January 1, 2009. The adoption of this FSP will not require additional disclosure by the Company regarding the current status of the payment/performance risk of guarantees as the Company currently has no guarantees within the scope of FIN No. 45 requiring disclosure.

 

 

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 at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the 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 Issue No. 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.

 

The Company utilizes either NYMEX published market prices, independent broker pricing data or broker/dealer valuations in determining the fair value of its derivative positions. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related, active market. Otherwise, they are considered Level 3.

 

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poors and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

 

The following table is a reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at September 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).

 

 

 

 

Gains and losses (realized and unrealized) included in earnings for the three and nine months ended September 30, 2008 attributable to the change in unrealized gains or losses relating to assets and liabilities held at September 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 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.

 

 

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 $0.5 million pre-tax ($0.3 million after tax, or less than $0.01 per basic and diluted share) and approximately $3.4 million pre-tax ($2.1 million after tax, or $0.02 per basic and diluted share), respectively, during the three and nine months ended September 30, 2008 related to the Company’s share-based payments. 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 and payouts of earned performance units. During the three and nine months ended September 30, 2008, there were 371,368 shares and 863,332 shares, respectively, of common stock issued pursuant to the Company’s Plans related to exercised stock options and payouts of earned performance units. The Company received approximately $7.2 million and $0.9 million during the three months ended September 30, 2008 and 2007, respectively, and approximately $14.7 million and $8.0 million during the nine months ended September 30, 2008 and 2007, respectively, related to exercised stock options.

 

 

In the third quarter of 2008, the Company issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture. During both the three and nine months ended September 30, 2008, there were 3,548 shares of restricted stock issued pursuant to the 2008 Plan.

 

In July 2005, the Company filed a Form S-3 Registration Statement to register 7,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”). Beginning in the third quarter of 2008, the Company began issuing new shares of common stock to satisfy the common stock requirements of the DRIP/DSPP. During both the three and nine months ended September 30, 2008, there were 111,017 shares of common stock issued to satisfy the common stock requirements of the DRIP/DSPP.

 

 

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

 

 

 

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 2005. In September 2008, the Internal Revenue Service completed its audit of tax years 2005 and 2006. 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.

 

 

 

 

 

 

 

At September 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):

 

(A) During the first six months of 2008, the interest rates for the Bonds were between 1.24% and 3.45%. In September 2008, the interest rates for the Bonds significantly increased to a one-week high of 8.35%. In late October 2008, the interest rates for the Bonds were between 2.39% and 2.50%.

 

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 except as discussed below. If the remarketing agent is unable to remarket any such Bonds, OG&E is obligated to repurchase such unremarketed Bonds. OG&E believes that it has sufficient long-term liquidity to meet these obligations.

 

OG&E’s remarketing agent for its Muskogee Industrial Authority variable-rate bonds, due June 1, 2027, was Lehman Brothers Holdings, Inc. (“Lehman”), which filed for bankruptcy protection on September 15, 2008. On September 22, 2008, Barclays Plc purchased the investment banking and capital markets operations of Lehman and replaced Lehman as OG&E’s new remarketing agent for its Muskogee Industrial Authority variable-rate bonds.

 

In September 2008, OG&E received a request for repayment of approximately $0.1 million of principal related to a portion of OG&E’s Muskogee Industrial Authority variable-rate bonds, due June 1, 2027. In September 2008, approximately $0.1 million of principal and accrued interest were paid to the bondholder. The $0.1 million of variable-rate industrial authority bonds is being actively remarketed by the remarketing agent.

 

 

The short-term debt balance was approximately $739.8 million and $295.8 million at September 30, 2008 and December 31, 2007, respectively. The following table shows the Company’s revolving credit agreements, term loan agreement and available cash at September 30, 2008.

 

 

 

(A) All of the lenders that participate in OGE Energy’s, OG&E’s and Enogex’s revolving credit agreements have funded their commitment, with the exception of Lehman, which filed for bankruptcy protection on September 15, 2008 and has not funded their portion of the revolving credit agreements. At September 30, 2008, approximately $4 million and $11 million, respectively, of OGE Energy’s and OG&E’s revolving credit agreements are not available as this portion was assigned to Lehman. As of October 15, 2008, the $15 million discussed above remains unassigned to another financial institution.   (B)  Includes direct borrowings, outstanding commercial paper and letters of credit at September 30, 2008.   (C) This bank facility is available to back up OGE Energy’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At September 30, 2008, there was approximately $496.7 million in outstanding borrowings under this revolving credit agreement. There were no outstanding commercial paper borrowings at September 30, 2008.   (D) This bank facility is available to back up OG&E’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At September 30, 2008, there was approximately $243.1 million in outstanding borrowings under this revolving credit agreement and approximately $0.3 million supporting letters of credit. There were no outstanding commercial paper borrowings at September 30, 2008.   (E)  In December 2006, OGE Energy and OG&E amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for OGE Energy and $400 million for OG&E. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods upon agreement of all parties in the revolving credit agreements. In November 2007, OGE Energy and OG&E utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at maturity to convert the outstanding balance to a one-year term loan.   (F)  Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements.   (G) On September 26, 2008, OG&E entered into a $200 million term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC maturing March 26, 2010. This loan can be used for general corporate purposes and permitted acquisitions as defined in the loan agreement. At September 30, 2008, there were no borrowings outstanding under this agreement. At October 15, 2008, there was approximately $50 million in outstanding borrowings under this agreement.   (H) On April 1, 2008, Enogex entered into a $250 million unsecured five-year revolving credit facility. Subject to certain limitations, the facility provides Enogex with the option, exercisable annually, to extend the maturity of the facility for an additional year and, upon the expiration of the revolving term, an option to convert the outstanding balance under the facility to a one-year term loan. The facility provides the option for Enogex to increase the borrowing limit by up to an additional $250 million (to a maximum of $500 million) upon the agreement of the lenders (or any additional lender) and the satisfaction of other specified conditions. This bank facility is available to provide revolving credit borrowings. At September 30, 2008, Enogex had approximately $120.0 million outstanding under this facility. These borrowings are not expected to be repaid within the next 12 months, therefore, they are classified as long-term debt for financial reporting purposes.

OGE Energy’s and OG&E’s ability to access the commercial paper market was adversely impacted by the market turmoil in September and October 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and OG&E utilized borrowings under their revolving credit agreements which bear a higher interest rate and a minimum 30-day maturity compared to commercial paper which had historically been available at lower interest rates and on a daily basis. OG&E also borrowed under the term loan discussed above. OGE Energy and OG&E expect to repay the borrowings under their revolving credit agreements and begin utilizing commercial paper in the commercial paper market when available.

 

In addition to general market conditions, OGE Energy’s and OG&E’s ability to access the commercial paper market could also be adversely impacted by a credit ratings downgrade. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of

 

 

the ratings of OGE Energy or 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 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.

 

The Company had a commercial paper arrangement with Lehman, which filed for bankruptcy protection on September 15, 2008. On September 22, 2008, Barclays Plc purchased the investment banking and capital markets operations of Lehman and replaced Lehman as the commercial paper dealer in the Company’s commercial paper arrangement.

 

Unlike OGE Energy 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 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, 2006 for the Company.

 

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

	Restoration of Retirement Plan
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Service cost	$	0.2	$	0.2	$	0.6	$	0.5
Interest cost		0.1		0.1		0.3		0.4
Amortization of net loss		0.1		3.0		0.2		3.1
Amortization of recognized prior service cost		0.2		0.2		0.5		0.5
Net periodic benefit cost (A)	$	0.6	$	3.5	$	1.6	$	4.5

(A) In addition to the $4.8 million and $9.5 million in SFAS No. 87, “Employers’ Accounting for Pensions,” net periodic benefit cost recognized during the three months ended September 30, 2008 and 2007, respectively, OG&E also recognized an expense of approximately $2.6 million and a gain of approximately $0.1 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 $14.2 million and $22.6 million in SFAS No. 87 net periodic benefit cost recognized during the nine months ended September 30, 2008 and 2007, respectively, OG&E also recognized an expense of approximately $7.6 million and $2.3 million, respectively, related to the reversal of a portion of the regulatory asset identified as Deferred Pension Plan Expenses (see Note 1).