(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).

 

 

 

Pension Plan Funding

 

In the third quarter of 2008, the Company contributed approximately $10 million to its pension plan for a total contribution of $50 million to its pension plan during 2008. No additional contributions are expected in 2008.

 

 

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 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 nine months ended September 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 nine months ended September 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.

 

 

 

 

 

(A) In 2004, the Company adopted a standard costing model utilizing a fully loaded activity rate (including payroll, benefits, other employee related costs and overhead costs) to be applied to projects eligible for capitalization or deferral. In March 2008, the Company determined that the application of the fully loaded activity rates had unintentionally resulted in the over-capitalization of immaterial amounts of certain payroll, benefits, other employee related costs and overhead costs in prior years. To correct this issue, in March 2008, the Company recorded a pre-tax charge of approximately $9.5 million ($5.8 million after tax, or $0.06 per basic and diluted share) as an increase in Other Operation and Maintenance Expense in the Condensed Consolidated Statements of Income for the three months ended March 31, 2008 and a corresponding $8.6 million decrease in Construction Work in Progress and $0.9 million decrease in Other Deferred Charges and Other Assets related to the regulatory asset associated with storm costs in the Condensed Consolidated Balance Sheets as of March 31, 2008.

 

 

 

 

Except as set forth below and in Note 13, the circumstances set forth in Notes 16 and 17 to the Company’s Consolidated Financial Statements included in the Company’s 2007 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.

 

Proposed Joint Venture

 

On September 22, 2008, OGE Energy entered into a Contribution Agreement with ETP pursuant to which OGE Energy and ETP agreed to form a joint venture company named ETP Enogex. ETP Enogex will be equally controlled by OGE Energy and ETP.

 

Pursuant to the Contribution Agreement, OGE Energy will contribute 100 percent of its ownership interest in Enogex to ETP Enogex. ETP will contribute 100 percent of its ownership interest in Transwestern Pipeline Company, LLC (“Transwestern”), 100 percent of its ownership interest in ETC Canyon Pipeline, LLC (“Canyon”) and its 50 percent interest in the entity that owns the Midcontinent Express Pipeline, LLC (“MEP”) to ETP Enogex.

 

Transwestern operates a pipeline system with 2,648 miles of natural gas transmission pipelines with total 2007 throughput of 1.8 billion cubic feet per day (“Bcf/d”), 19 interconnection points with interstate and intrastate pipelines and 347,745 horsepower of compression.

 

Canyon operates a pipeline system with more than 1,300 miles of natural gas gathering pipelines in Utah and Colorado with 193 million cubic feet per day (“MMcf/d”) of capacity as currently configured; 300 MMcf/d with added compression and processing. Canyon has six processing plants for natural gas liquids extraction and treating, with 90 MMcf/d of capacity and two NGL injection points on Enterprise Mid-Continent Pipeline, four interstate interconnects with Questar, Northwest, Source Gas and TransColorado.

 

MEP is a 50/50 joint venture between ETP and Kinder Morgan Energy Partners, L.P. The pipeline project is expected to be completed in the second quarter of 2009. When completed, the project will include a 500-mile FERC regulated pipeline originating at an Enogex connection near Bennington, Oklahoma, routing through Perryville, Louisiana, and terminating at an interconnect with Transco in Butler, Alabama. Initial capacity is estimated at 1.5 Bcf/d.

 

Subject to any dilution resulting from the issuance of new equity by ETP Enogex and except as described below, each of OGE Energy and ETP will be entitled to receive 50 percent of the cash distributions made by ETP Enogex. However, OGE Energy will be entitled to (a) 55 percent of any cash distributions made by ETP Enogex prior to June 30, 2010 and (b) 75 percent of any cash distributions that exceed specified quarterly distribution amounts for the three-year period following consummation of this transaction, with the total additional distributions pursuant to these two disproportionate distribution mechanisms capped at approximately $50 million.

 

20

 

 

Consummation of the transaction is conditioned on antitrust approval, receipt of certain third-party consents and certain other customary closing conditions. The transaction is also conditioned upon obtaining financing pursuant to a specified financing plan that would provide funding for payments from ETP Enogex to OGE Energy and ETP at the closing of the transaction as well as other financings for ETP Enogex to provide longer-term credit capacity. Specifically, the financing plan (the “Financing Plan”) specifies that (a) ETP Enogex would, at a minimum, enter into a $700 million senior secured revolving credit facility, (b) ETP Enogex would issue approximately $800 million of senior unsecured notes and (c) Transwestern would issue approximately $800 million in senior unsecured notes. ETP Enogex’s senior secured credit facility would be expected to be undrawn at closing and available for future capital expenditures and working capital. The proceeds from the issuance of the ETP Enogex senior notes and the Transwestern senior notes would be expected to be used to: (i) make a $266 million cash distribution to OGE Energy, (ii) prepay all of the currently outstanding Transwestern notes, (iii) repay any intercompany loans made by ETP to Transwestern, (iv) repay amounts outstanding under Enogex’s credit facility and (v) repay any intercompany loans made by OGE Energy to Enogex. Under the terms of the agreement, if OGE Energy and ETP do not complete the Financing Plan and close the joint venture no later than March 31, 2009, either party can cancel the agreement. In today’s market, it would be difficult for the joint venture to complete the Financing Plan under the agreed to terms, but OGE Energy and ETP are working with their banking teams to monitor the market and evaluate the funding options. OGE Energy filed a Hart-Scott-Rodino (“HSR”) form on October 6, 2008 in connection with the transaction. The HSR waiting period will expire in early November 2008 unless extended by a request for additional information from either the Federal Trade Commission or the United States Department of Justice. OGE Energy remains committed to the transaction due to its strategic benefits.

 

Pending closing of the transaction, each of the parties has agreed that the entities being contributed to the joint venture shall not make distributions to their respective sponsors.

 

Upon consummation of the transaction, each of OGE Energy and ETP will agree that, subject to certain exceptions, the following projects and activities must be owned, developed, operated and conducted through ETP Enogex: (i) all intrastate natural gas and natural gas liquids transportation assets in the designated area described below, (ii) all natural gas and natural gas liquids processing and storage assets in the designated area, (iii) all interstate natural gas and natural gas liquids pipelines if any portion is located within the designated area, (iv) any expansion or extension of the Transwestern pipeline and (v) extensions of the Midcontinent Express pipeline. The designated area includes the State of Oklahoma and the counties in the Texas Panhandle, New Mexico, Arkansas, Colorado and Utah where the assets of Enogex and ETC Canyon Pipeline are currently located. Each of OGE Energy and ETP and their respective affiliates would be precluded from making acquisitions of which a majority of the assets (based on fair market value) are located inside the designated area. However, upon consummation by ETP Enogex of such an acquisition that includes assets in Texas that are outside the designated area, ETP Enogex would be required to offer OGE Energy the opportunity to acquire any assets located in Texas that are outside the designated area for the fair market value of such assets. Neither party would be precluded from making acquisitions of which a majority of the assets (based on fair market value) are located outside the designated area. However, upon consummation of such an acquisition, OGE Energy or ETP, as applicable, would be required to offer ETP Enogex the opportunity to acquire any assets located within the designated area for the fair market value of such assets.

 

OG&E Railcar Lease Agreement

 

At December 31, 2007, OG&E had a noncancellable operating lease with purchase options, covering 1,409 coal hopper railcars to transport coal from Wyoming to OG&E’s coal-fired generation units. In April 2008, OG&E amended its contract to add 55 new railcars for approximately $3.5 million. At the end of the new lease term, which is January 31, 2011, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of approximately $31.5 million.

 

OG&E Coal Transportation Contracts

 

OG&E has transportation contracts for the transportation of coal to its coal-fired power plants. OG&E’s current transportation contracts expire on December 31, 2008. OG&E is currently in the process of negotiating new contracts and expects its new contracts to contain higher transportation rates than in the current contracts.

 

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 January 2008 through the remainder of the term. OERI’s new demand fee obligations, net of this turn back and other immaterial release agreements, are estimated to be approximately $5.1 million in 2008; $5.3 million for each of the years 2009 through 2012; $6.4 million for each of the years 2013 and 2014 and $1.7 million in 2015.

 

Agreement with Midcontinent Express Pipeline, LLC

 

In December 2006, Enogex entered into a firm capacity lease agreement with MEP for a primary term of 10 years (subject to possible extension) that would give MEP and its shippers access to capacity on Enogex’s system. The quantity of capacity subject to the MEP lease agreement is currently 272 MMcf/d, with the quantity ultimately to be leased subject to being increased by mutual agreement pursuant to the lease agreement. In addition to MEP’s lease of Enogex’s capacity, the MEP project includes construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Enogex currently estimates that its capital expenditures related to this project will be approximately $94 million.

MEP filed an application with the FERC on October 9, 2007 requesting a certificate of public convenience and necessity authorizing MEP to construct its pipeline and lease certain capacity from Enogex. On October 9, 2007, Enogex also filed an application with the FERC for issuance of a limited jurisdiction certificate authorizing its lease agreement with MEP. On July 25, 2008, the FERC issued its order approving the MEP project including the approval of a limited jurisdiction certificate authorizing the Enogex lease agreement to MEP. Further, the FERC order rejected all claims raised by protestors regarding the lease agreement.  Accordingly, Enogex is proceeding with the construction of facilities necessary to implement this service.  On August 25, 2008, one protestor filed a request for rehearing. The FERC has not yet ruled on the request for rehearing. The MEP project is currently expected to be in service during the second quarter of 2009.

 

Franchise Fee Lawsuit

 

On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law.  OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.   In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges. Motions to set a procedural schedule and determine notice requirements for the matter are scheduled to be heard by the OCC on November 6, 2008.  OG&E believes that this case is without merit.

 

Oxley Litigation

 

OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs’ alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiff in amounts set forth in the contracts.  The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. OG&E expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

 

Environmental Laws and Regulations

 

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 February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule and on March 24, 2008, the EPA filed a petition for rehearing. On May 20, 2008, the U.S. Court of Appeals for the D.C. Circuit denied the petition.  On October 17, 2008, the U.S. Department of Justice, on behalf of the EPA, petitioned the U.S. Supreme Court for a writ of certiorari to review the judgment of the D.C. Circuit Court of Appeals in the CAMR case. The

 

 

In September 2005, the ODEQ informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in national parks and wilderness areas (“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. The due date for the ODEQ submission of the state implementation plan was December 17, 2007; however, the ODEQ has not yet submitted a plan to the EPA for approval. 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 cost for this alternative compliance plan, including the BART compliance plan for the Seminole power plant (the alternative compliance plan and the BART compliance plan are collectively referred to herein as the “alternative plan”), was estimated at approximately $470 million in March 2007. The alternative plan included installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan was subject to approval by the ODEQ and the EPA. The EPA provided an opinion to the ODEQ that OG&E’s alternative plan did not meet the requirements of the regional haze rules. On November 16, 2007, the ODEQ notified OG&E that additional analysis would be required before the OG&E alternative plan could be accepted. As required by the ODEQ, OG&E completed additional analysis and, on May 30, 2008, OG&E filed with the ODEQ the results of its BART evaluation for the affected generating units as well as withdrawing its alternative plan filed in March 2007. In the May 30, 2008 filing, OG&E indicated its intention to install low NOX combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. OG&E believes that these control measures will achieve visibility improvements in a cost-effective manner. OG&E did not propose the installation of scrubbers at its four coal-fired generating units because OG&E concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. OG&E cannot predict what action the EPA or the ODEQ will take in response to OG&E’s May 30, 2008 filing. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by OG&E with a reasonable degree of certainty. 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.

 

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone of 0.08 parts per million (“PPM”). In March 2008, the EPA lowered the ambient primary and secondary standards to 0.075 PPM. Oklahoma has until March 2009 to designate any areas of non-attainment within the state, based on ozone levels in 2006 through 2008. Following the state’s designation, the EPA is expected to determine a final designation by March 2010. States will be required to meet the ambient standards between 2013 and 2030, with deadlines depending on the severity of their ozone level. Oklahoma City and Tulsa are the most likely areas to be designated non-attainment in Oklahoma. The Company cannot predict the final outcome of this evaluation or its timing or affect on OG&E’s or Enogex’s operations.

 

At December 31, 2007, OG&E had received Title V permits for all of its generating stations and intends to continue to renew these permits as necessary. In January 2008, the ODEQ proposed fee increases of approximately 28 percent for Title V sources and 13 percent for minor sources. These fee increases were approved and became effective July 1, 2008. Air permit fees

 

 

for OG&E’s generating stations were approximately $0.8 million in 2008 and for Enogex’s facilities were approximately $0.3 million in 2008.

 

In July 2008, OG&E received a request for information from the EPA regarding Clean Air Act compliance at OG&E’s Muskogee and Sooner generating plants.  In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Clean Air Act’s new source review process.  OG&E believes it has acted in full compliance with the Clean Air Act and new source review process and is cooperating with the EPA.   On August 28, 2008, OG&E submitted information to the EPA and advised the EPA that it intends to submit additional information on or before October 31, 2008.  OG&E cannot predict what, if any, further actions the EPA may take with respect to this matter. 

 

Water

 

OG&E filed an Oklahoma Pollutant Discharge Elimination System renewal application with the state of Oklahoma on August 4, 2008 for its Seminole power plant.

 

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. 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 required a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility.  On January 7, 2008, OG&E submitted the requested studies for its facilities. Additionally, on April 14, 2008, the U.S. Supreme Court granted writs of certiorari and will review the question of whether the Section 316(b) rules authorize the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. 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 comprehensive demonstration studies, 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 16 and 17 of Notes to the Company’s Consolidated Financial Statements included in the Company’s 2007 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 17 to the Company’s Consolidated Financial Statements included in the Company’s 2007 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

 

Completed Regulatory Matters

 

Enogex 2008 Fuel Filing

 

As required by the fuel tracker provisions of its Statement of Operating Conditions, Enogex files annually to update its fuel percentages for the East Zone and the West Zone. On November 15, 2007, Enogex made its annual filing to establish the fixed fuel percentages for its East Zone and West Zone for calendar year 2008 (“2008 Fuel Year”). There were no protests and the FERC accepted the proposed zonal fuel percentages for 2008 Fuel Year by order of December 19, 2007. Enogex expects to file its next annual fuel filing to establish fuel percentages for calendar year 2009 on or about November 15, 2008.

 

 

Cancelled Red Rock Power Plant

 

On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, OG&E requested authorization to sell approximately $14.7 million of its sulfur dioxide (“SO2”) allowances and to retain 100

 

Renewable Energy Filing

 

OG&E announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, OG&E expects to issue a request for proposal for wind power generation in the fourth quarter of 2008.

 

OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma at a cost of approximately $211 million. This transmission line is a critical first step to increased wind development in western Oklahoma. In the application, OG&E also requested authorization to implement a recovery rider to be effective when the transmission line is completed and in service, which is expected during 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to OG&E’s Oklahoma customers. On July 11, 2008, the OCC Staff filed responsive testimony recommending approval of OG&E’s renewable plan and the Oklahoma Industrial Energy Consumers opposed OG&E’s request. A settlement agreement was signed by all parties in the matter on July 31, 2008. Under the terms of the settlement agreement, the parties agreed that the Company will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and allowance for funds used during construction (“AFUDC”) when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million OG&E be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above.

 

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. In September 2008, the OCC issued an order approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2006.

 

Pending Regulatory Matters

 

OG&E FERC Formula Rate Filing

 

On November 30, 2007, OG&E made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on OG&E’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of OG&E’s filing. OG&E filed an

 

OG&E Arkansas Rate Case Filing

 

Beginning in early 2008, OG&E began developing a rate case filing for the Arkansas jurisdiction. In June 2008, OG&E filed a notice with the APSC that it expected to file its rate case in August 2008. On August 29, 2008, OG&E filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that OG&E can reliably meet growing customer demand for electricity. If approved by the APSC, new rates are expected to go into effect in mid-2009.

 

OG&E 2008 Storm Cost Filing

On October 30, 2008, OG&E filed an application with the APSC requesting authority to defer its 2008 storm costs that exceed the amount recovered in base rates. At September 30, 2008, these incremental storm costs were approximately $0.6 million and will be updated at the end of 2008. The application also requests the APSC to provide for recovery of the deferred 2008 storm costs in OG&E’s pending rate case.

 

Enogex FERC Section 311 2007 Rate Case

 

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for service in the East Zone and West Zone. Enogex’s filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some also filed protests.

 

The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. By order of February 28, 2008, the FERC extended the time period in this docket by 120 days and encouraged the parties to settle. No action has yet been taken by the FERC and the parties are currently in settlement negotiations.

 

On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the new MEP pipeline and to lease firm capacity from Enogex. Additional pleadings have been filed by this intervenor and Enogex and MEP have separately opposed this intervenor’s assertions. By order dated July 25, 2008, the FERC approved the MEP project and denied the intervenors’ request for consolidation of the MEP proceedings with the Enogex rate case. Enogex has not, as of yet, placed the increased rates into effect. Enogex must file its next rate case no later than October 1, 2010 to comply with the FERC’s requirement for triennial filings.

 

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.

 

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.

  

 

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, OG&E submitted: (i) a compliance filing containing the specified revisions to OG&E’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. On April 4, 2008, the FERC rejected OG&E’s April 20, 2006 request for rehearing and approved in part and rejected in part OG&E’s April 20, 2006 compliance filing. The April 4, 2008 order directed OG&E to evaluate whether any refunds are required to comply with the April 4, 2008 order and to: (i) make any necessary refunds, or (ii) file a report with the FERC stating that no refunds are due. Refunds would apply only to new market-based sales made or new market-based contracts entered into after the March 21, 2006 order. The April 4, 2008 order also directed OG&E to make another compliance filing to revise its market-based rate tariffs to adhere to the FERC’s June 21, 2007 final rule that revised standards for market-based rate sales of electric energy, capacity and ancillary services. On May 5, 2008, OG&E submitted a compliance report stating that no refunds were due. On May 30, 2008, OG&E and OERI submitted to the FERC a change in status report notifying the FERC that OG&E had entered into a contract with Westar Energy under which OG&E agreed to purchase 300 MWs of capacity and energy for the periods from May 1, 2008 through August 31, 2008, and from May 1, 2009  through August 31, 2009.  OG&E and OERI explained that this purchase agreement was not material to the FERC’s grant of market-based rate status to OG&E and OERI. The FERC has not yet acted on OG&E’s and OERI’s change of status filing.

 

National Legislative Initiatives

 

In October 2008, Congress enacted and the President signed into law the Emergency Economic Stabilization Act of 2008 which contains, among other things, provisions designed to provide programs to: (i) address the nation’s credit liquidity problems; (ii) provide disaster relief for adversely affected communities; (iii) preserve the value of homes, retirement accounts and promote job creation; and (iv) implement a wide range of tax provisions, including several of particular interest to the investor-owned utility sector. Among the tax provisions benefitting the utility sector are the extension of tax credits for renewable energy production, carbon mitigation and clean coal technology, plug-in hybrid vehicles, increasing residential and commercial building energy efficiency, energy efficient appliances and accelerated depreciation for smart meters and smart grid systems. Of particular interest to the Company is the extension through 2009 of the renewable energy production tax credit that was scheduled to expire at the end of 2008, which plays a prominent role regarding the financing and economics of wind energy projects.

 

 

As discussed in Note 13, on September 29, 2008, OG&E purchased the entire partnership interest in the Redbud Facility using the following sources of cash: (i) net proceeds from the issuance by OG&E of $250 million of 6.35% senior notes due September 1, 2018 in early September 2008, which net proceeds were temporarily used to repay a portion of the Company’s outstanding commercial paper borrowings, (ii) $300 million of borrowings under a term loan agreement OG&E entered into with Royal Bank of Scotland PLC (“RBS”) on September 26, 2008 and (iii) borrowings under OGE Energy’s and OG&E’s revolving credit agreements. Also, on September 29, 2008, after OG&E purchased the entire partnership interest in the Redbud Facility, the OMPA and the GRDA purchased their respective undivided interests in the Redbud Facility from OG&E for approximately $417.5 million. After the closing of the sale of the undivided interests in the Redbud Facility, OG&E used the $417.5 million in proceeds and repaid in full, on September 30, 2008, the $300 million borrowed from RBS discussed above and invested the remainder of the proceeds in short-term investments which are recorded as Cash and Cash Equivalents on the Company’s

 

 

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

 

Introduction

 

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

 

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. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the 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 OGE Energy and ETP 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. Under the terms of the agreement, OGE Energy will contribute to ETP Enogex Partners LLC 100 percent of its ownership interest in Enogex and ETP will contribute 100 percent of its ownership interests in Transwestern Pipeline Company, LLC and ETC Canyon Pipeline, LLC and its 50 percent interest in Midcontinent Express Pipeline, LLC. OGE Energy and ETP expect to complete the formation of the joint venture after obtaining satisfactory financing, customary regulatory approvals and various third-party consents. There is no guarantee that the joint venture will be successfully completed. For additional information regarding the joint venture, see Note 12 of Notes to Condensed Consolidated Financial Statements. 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 joint venture is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned transmission construction. Work on the joint venture projects is scheduled to begin in late 2009 and is targeted for completion by the end of 2013. The joint venture projects are subject to creation by the Southwest Power Pool (“SPP”) of a cost allocation method that would spread the total cost across the SPP region. The project also requires approval from the FERC. OGE Energy plans to file an application with the FERC during the fourth quarter of 2008 for cost recovery of these projects subject to SPP and FERC approval for these projects. OGE Energy may also seek approval from the OCC. The joint venture’s initial projects will include 765 kilovolt lines from Woodward 120 miles northwest to Guymon in the Oklahoma Panhandle and from Woodward 50 miles north to the Kansas border. An SPP study estimates cost for the two projects to be approximately $500 million.

 

 

 

 

 

Recent Developments and Regulatory Matters

 

Changes in the Capital, Credit and Commodity Markets

 As a result of recent volatile conditions in global capital markets, including the bankruptcy filing of Lehman Brothers Holdings, Inc. (“Lehman”), general liquidity in short-term credit markets has been constrained despite several pro-active intervention measures undertaken by the Federal Reserve, the Department of the Treasury, the United States Congress and the President of the United States. As explained in more detail below, OGE Energy and OG&E historically have maintained access to short-term liquidity through the A2/P2 commercial paper market and utilization of direct borrowings on certain committed credit agreements, although the ability to access the commercial paper market has been more limited in recent weeks. 

The recent volatility in global capital markets has lead to a reduction in the current value of long-term investments held in OGE Energy’s pension trust and post-retirement benefit plan trusts. The recent decline in asset value for the plans, if it continues for any length of time, could require additional future funding requirements.

On September 15, 2008, Lehman filed for bankruptcy protection. The Company has no direct credit exposure in its short-term wholesale and commodity trading activity to Lehman or its subsidiaries.

Enogex’s gathering and processing margins generally improve when NGL prices are high relative to the price of natural gas (sometimes referred to as high commodity spreads). For much of the first nine months of 2008, commodity spreads were relatively high. Recently, commodity spreads have been significantly lower. If this trend continues, Enogex’s results for 2008 and 2009 will be affected. See 2009 Outlook below. Also, prices of natural gas and NGLs have been extremely volatile, and Enogex expects this volatility to continue.

 

Acquisition of Redbud Power Plant

 

On September 29, 2008, OG&E acquired a 51 percent interest in a 1,230 megawatt (“MW”) natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“Redbud Facility”) for approximately $434.5 million. OG&E will jointly own the Redbud Facility with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority, and OG&E will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Each of the joint owners will be entitled to its respective portion of the output and will pay its pro rata share of all costs of operating and maintaining the Redbud Facility. OG&E implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes. For additional information regarding the acquisition of the Redbud Facility, see Notes 13 and 14 of Notes to Condensed Consolidated Financial Statements.

 

Cancelled Red Rock Power Plant

 

On October 11, 2007, the OCC issued an order denying OG&E and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at OG&E’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, OG&E, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, OG&E had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, OG&E filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, OG&E requested authorization to sell approximately $14.7 million of its sulfur dioxide (“SO2”) allowances and to retain 100 percent of the proceeds to offset the $14.7 million of Red Rock costs. Under a prior order of the OCC, 90 percent of the proceeds from sales of SO2 allowances were to be credited to ratepayers. Any portion of the $14.7 million of deferred costs that the OCC did not approve for recovery by OG&E was to be expensed. In its response to OG&E’s Red Rock cost recovery application, the OCC Staff recommended, among other things, that OG&E sell SO2 allowances and retain 100 percent of the proceeds from the sale to be used to offset OG&E’s December 2007 ice storm costs. These ice storm costs were included as part of the regulatory asset balance of approximately $35.9 million at December 31, 2007 (see Note 1 of Notes to Condensed Consolidated Financial Statements), in accordance with a prior order of the OCC, pending recovery in a future rate case. On June 27, 2008, OG&E filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, OG&E will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with OG&E’s

 

 

 

next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date OG&E begins to recover the regulatory asset through the base rates established in OG&E’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in OG&E’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover OG&E’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess SO2 allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 allowances above the amount retained by OG&E and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. On June 30, 2008, OG&E wrote down the Red Rock deferred cost to its net present value, which resulted in a pre-tax charge of approximately $7.5 million, which is currently included in Deferred Charges and Other Assets with an offset in Other Expense on the Company’s Condensed Consolidated Financial Statements. The write-downs of deferred costs for both the Red Rock power plant and storm costs resulted in a pre-tax charge of approximately $9.0 million for the quarter ended June 30, 2008.

 

OG&E Arkansas Rate Case Filing

 

Beginning in early 2008, OG&E began developing a rate case filing for the Arkansas jurisdiction. In June 2008, OG&E filed a notice with the APSC that it expected to file its rate case in August 2008. On August 29, 2008, OG&E filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that OG&E can reliably meet growing customer demand for electricity. If approved by the APSC, new rates are expected to go into effect in mid-2009.

 

OG&E Proposed Wind Power Project

 

OG&E signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with a future wind project in western Oklahoma. OG&E will seek regulatory recovery from the OCC and plans to have this project in-service by the end of 2009. Capital expenditures associated with this project are expected to be approximately $260 million.

 

Texas Panhandle / West Side Expansions

 

In August 2006, Enogex completed a project to expand its gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed Enogex to benefit from growth opportunities in that marketplace. Since the pipeline was put in service, Enogex has completed the construction of five new gas gathering compressor stations totaling approximately 26,500 horsepower of compression, and several miles of gathering pipe, including a new 16-inch line that extends the original pipeline project an additional 20 miles to the west.  Enogex is continuing to expand in the Wheeler and Hemphill counties in Texas and has several additional projects scheduled for completion in 2009. For example, Enogex expects to complete the following projects: (i) add another 1,300 horsepower of compression to the Wheeler area by March 2009 and (ii) add another 16,000 horsepower of low pressure compression to the Wheeler area by October 2009.

 

Southeastern Oklahoma / East Side Expansions

 

In February 2008, Enogex completed construction of a new 20-mile pipeline project that connects Enogex’s Hughes, Coal and Pittsburgh county gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma.  The gathering project created additional gathering capacity of 75 million cubic feet per day (“MMcf/d”) for customers desiring low-pressure services. The pipeline was complemented by approximately 16,000 horsepower of new gathering compression which was completed in the third quarter of 2008.

 

Enogex Additional Processing Capacity

 

Enogex will consider building or acquiring additional processing capacity in areas where the capacity is needed. Enogex completed construction of a new 100 MMcf/d refrigeration dew point conditioning plant in Roger Mills County of Oklahoma, which became operational in August 2008. In addition, Enogex is constructing a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant will process new gas developing in the area and is expected to be in service by June 2009.

 

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2008 Outlook

 

The Company previously disclosed in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 that its 2008 earnings guidance had increased to $234 million to $253 million of net income, or $2.50 to $2.70 per diluted share, as shown in the table below, primarily as a result of high commodity spreads. Due primarily to the recent significant decrease in commodity spreads, the Company has lowered its 2008 earnings guidance to $224 million to $238 million, or $2.40 to $2.55 per diluted share, as shown in the table below, and assuming approximately 93.2 million average diluted shares outstanding and an effective tax rate of 31.4 percent.

 

	Earnings guidance per		Revised earnings guidance per
	Q2 2008 Form 10-Q		Q3 2008 Form 10-Q
(In millions, except per share data)	Dollars	Diluted EPS	Dollars	Diluted EPS
OG&E	$128 - $138	$1.37 - $1.47	$135 - $140	$1.45 - $1.50
Enogex	$105 - $122	$1.12 - $1.30	$  89 - $  96	$0.95 - $1.03
Holding Company & OERI	$    0 - $    2	$0.00 - $0.02	$    0 - $    2	$0.00 - $0.02
Consolidated	$234 - $253	$2.50 - $2.70	$224 - $238	$2.40 - $2.55

 

Key assumptions for 2008 are:

As shown above, OG&E’s earnings guidance has been increased from $128 million to $138 million, or $1.37 to $1.47 per diluted share, to $135 million to $140 million, or $1.45 to $1.50 per diluted share. As explained below, this increase is attributable to a lower effective tax rate at OG&E primarily resulting from higher levels of state investment tax credits associated with capital expenditures and lower interest expense due to a lower than previously anticipated level of long-term debt. Key factors and assumptions underlying this guidance include:

OG&E

	•	Gross margin on weather-adjusted, retail electric sales increase of approximately two percent remains unchanged;
	•	Operating expenses of approximately $565 million remain unchanged;
	•	Interest expense of approximately $77 million compared to approximately $79 million in the previous guidance primarily due to lower interest expense on lower than previously anticipated levels of long-term debt;
	•	An effective tax rate of approximately 27.7 percent compared to approximately 30.0 percent in the previous guidance due to higher levels of state investment tax credits associated with capital expenditures; and
	•	Capital expenditures for investment in OG&E’s generation, transmission and distribution system of approximately $850 million in 2008, which includes capital expenditures of approximately $435 million associated with OG&E’s acquisition of the Redbud Facility. Previous guidance assumed approximately $843 million of capital expenditures. The increase is primarily due to the renewable energy proposal and the proposed wind power project.

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 has been decreased from $105 million to $122 million, or $1.12 to $1.30 per diluted share, to $89 million to $96 million, or $0.95 to $1.03 per diluted share. Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”) is between $236 million to $247 million. Key factors and assumptions underlying this guidance include:

 

•		Total Enogex anticipated gross margin of approximately $394 million to $405 million as compared to approximately $421 million to $449 million assumed in the previous earnings guidance. The revised guidance includes:
		•	Transportation and storage gross margin contribution of approximately $144 million compared to approximately $138 million in the previous earnings guidance;
		•	Gathering and processing gross margin contribution of approximately $250 million to $261 million as compared to approximately $283 million to $311 million assumed in the previous earnings guidance primarily due to decreased commodity price assumptions. Key factors affecting the revised gathering and processing gross margin are:

 

33

•

Commodity price assumptions are below;

		Q2 2008 10-Q			Revised
		Low	High		Low	High
		Guidance	Guidance		Guidance	Guidance
	Natural Gas Price ($ per MMBtu)	$10.25	$8.60		$7.68	$7.19
	Weighted Average Natural Gas Liquids Price ($ per gallon)	$1.52	$1.79		$1.21	$1.31
	Realized Weighted Average Commodity Spreads ($ per MMBtu)	$7.03	$8.32		$6.17	$6.26

 

 

 

 

 

 

 

 

	•		The realized commodity spread takes into account that 66 percent of processing volumes that bear price risk are hedged;
	•		Operating expenses of approximately $209 million compared to approximately $207 million in the previous guidance;
	•		Interest expense of approximately $35 million compared to approximately $33 million in the previous guidance, primarily due to higher short-term interest rates; and
	•		Capital expenditures for investment in Enogex’s pipeline system of approximately $324 million in 2008 as compared to approximately $370 million in the previous guidance. The decrease in capital expenditures is primarily due to additional growth projects that have been delayed until 2009 compared to the previous guidance reported in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008.

  

     Reconciliation of projected EBITDA to projected net cash provided from operating activities

	Twelve Months Ended
(In millions)	December 31, 2008 (A)
Net cash provided by operating activities	$	192.7
Interest expense, net		34.5
Changes in operating working capital which provided (used) cash:
Accounts receivable		94.4
Accounts payable		11.4
Other, including changes in noncurrent assets and liabilities		(91.9)
EBITDA	$	241.1

(A)

Based on midpoint of 2008 guidance.

 

     Reconciliation of projected EBITDA to projected net income

	Twelve Months Ended
(In millions)	December 31, 2008 (A)
Net Income	$	92.3
Add:
Interest expense, net		34.5
Income tax expense		59.0
Depreciation and amortization		55.3
EBITDA	$	241.1

(A)

Based on midpoint of 2008 guidance.

 

For a discussion of the reasons for the use of EBITDA, as well as the limitations of EBITDA as an analytical tool, see “Enogex’s Non-GAAP Financial Measures” below.

Holding Company

As shown above, the projected earnings guidance at the holding company remains unchanged and excludes any transaction costs (approximately $9 million or $0.06 per diluted share) that may be expensed in 2008 associated with the proposed

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joint venture with ETP. On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy and OERI’s projected results for 2008 are included in the holding company’s projected results for 2008.

2009 Outlook

The Company’s 2009 earnings guidance is between $220 million and $248 million of net income, or $2.30 to $2.60 per diluted share assuming approximately 95.5 million average diluted shares outstanding and an effective tax rate of 29.9 percent.

 

(In millions, except per share data)	Dollars	Diluted EPS
OG&E	$ 179 - $191	$   1.87 - $  2.00
Enogex	$   51 - $  75	$   0 53 - $  0.79
Holding Company & OERI	$ (14) - $(16)	$ (0.15)- $(0.17)
Consolidated	$ 220 - $248	$  2.30 - $  2.60

 

Key assumptions for 2009 are:
 

OG&E

As shown above, OG&E’s earnings guidance for 2009 is between $179 million to $191 million, or $1.87 to $2.00 per diluted share of the Company’s common stock. The key factors and assumptions underlying this guidance are risk-adjusted to determine the ranges described above. Therefore, the ranges by component may not add to the total. The key factors and assumptions include:

 

	•	Normal weather patterns are experienced for the year;
	•	Gross margin on weather-adjusted, retail electric sales increases approximately one percent;
	•	Oklahoma annual rate increase of approximately $79 million implemented in the last half of 2009 (a $10 million change in rates equates to approximately $0.07 of earnings per diluted share on an annual basis);
	•	Arkansas annual rate increase of approximately $13 million implemented in mid-2009;
	•	Storm cost recovery rider of approximately $9 million;
	•	Operating expenses of approximately $608 million;
	•	Interest costs of approximately $90 million;
	•	An effective tax rate of approximately 29.7 percent; and
	•	Capital expenditures for investment in OG&E’s generation, transmission and distribution system of approximately $587 million in 2009.

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 $51 million to $75 million, or $0.53 to $0.79 per diluted share of the Company’s common stock. EBITDA is between $194 million to $232 million. Although the Company remains committed to the joint venture with ETP, projected earnings from the joint venture are not reflected in the 2009 Enogex earnings guidance. Key factors and assumptions underlying this guidance include:

 

	•	Total Enogex anticipated gross margin of approximately $353 million to $391 million. The 2009 guidance assumes:

•

Transportation and storage gross margin contribution of approximately $145 million;

	•	Gathering and processing gross margin contribution of approximately $208 million to $246 million. Key factors affecting the gathering and processing gross margin forecast are:

•

Assumed increase of seven percent in gathered volumes over 2008;

•

Assumed natural gas prices of $5.51 to $7.27 per MMBtu in 2009;

•

Assumed realized commodity spreads of $2.19 to $3.16 per MMBtu in 2009. The realized commodity spread takes into account that 81 percent of non-ethane processing volumes that bear price risk are hedged and the amortized cost of the hedges is included in the realized commodity spread calculation;

•

Assumed weighted average natural gas liquids prices of $0.66 to $0.90 per gallon in 2009;

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•

Operating expenses of approximately $225 million;

	•	Interest expense of approximately $44 million in 2008; and
	•	Capital expenditures for investment in Enogex’s pipeline system of approximately $277 million in 2009.

     Reconciliation of projected EBITDA to projected net cash provided from operating activities

 

	Twelve Months Ended
(In millions)	December 31, 2009 (A)
Net cash provided by operating activities	$	168.8
Interest expense, net		43.9
Changes in operating working capital which provided (used) cash:
Accounts receivable		84.0
Accounts payable		11.4
Other, including changes in noncurrent assets and liabilities		(95.2)
EBITDA	$	212.9

(A)

Based on midpoint of 2009 guidance.

   

     Reconciliation of projected EBITDA to projected net income

 

	Twelve Months Ended
(In millions)	December 31, 2009 (A)
Net Income	$	63.2
Add:
Interest expense, net		43.9
Income tax expense		34.8
Depreciation and amortization		71.0
EBITDA	$	212.9

	(A)	Based on midpoint of 2009 guidance.

For a discussion of the reasons for the use of EBITDA, as well as the limitations of EBITDA as an analytical tool, see “Enogex’s Non-GAAP Financial Measures” below. 

 

Holding Company

 

As shown above, the projected net loss at the holding company is between $14 million and $16 million, or $0.15 to $17 per diluted share, primarily due to interest expense relating to long and short-term debt borrowings.

 

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, 2008 as compared to the same period in 2007 and the Company’s consolidated financial position at September 30, 2008. 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 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.

 

 

 

 

 

Operating Income (Loss) by Business Segment

(A) On January 1, 2008, Enogex distributed the stock of OERI to OGE Energy, and as a result, OERI is no longer a subsidiary of Enogex.

(B) Other Operations primarily includes the operations of the holding company and consolidating eliminations.

 

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

 

 

 

 

 (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.

 

 

 

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

 

OG&E’s operating income decreased approximately $9.1 million during the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to a lower gross margin, which is operating revenues less cost of goods sold, higher operating expenses and higher depreciation and amortization expense.

 

Gross Margin

 

Gross margin was approximately $301.6 million during the three months ended September 30, 2008 as compared to approximately $306.3 million during the same period in 2007, a decrease of approximately $4.7 million, or 1.5 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 $283.4 million during the three months ended September 30, 2008 as compared to approximately $231.2 million during the same period in 2007, an increase of approximately $52.2 million, or 22.6 percent, primarily due to higher natural gas prices. OG&E’s electric generating capability is fairly evenly divided between coal and natural gas. Purchased power costs were approximately $97.5 million during the three months ended September 30, 2008 as compared to approximately $95.2 million during the same period in 2007, an increase of approximately $2.3 million, or 2.4 percent, primarily due to purchases from other utilities and cogenerations partially offset by a decrease in purchases in the energy imbalance service market.

 

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. See Note 1 of Notes to Condensed Consolidated Financial Statements for a discussion of fuel clause under recoveries.

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $79.9 million during the three months ended September 30, 2008 as compared to approximately $78.5 million during the same period in 2007, an increase of approximately $1.4 million, or 1.8 percent. The increase in other operation and maintenance expenses was primarily due to:

 

 

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

 

 

 

Additional Information

 

Interest Income. Interest income was approximately $1.7 million during the three months ended September 30, 2008. There was no interest income during the same period in 2007. The increase in interest income was primarily due to interest from customers related to the fuel under recovery balance during the three months ended September 30, 2008.

 

Other Income (Loss). Other income includes, among other things, contract work performed for third parties, non-operating rental income and miscellaneous non-operating income. Other loss was approximately $1.1 million during the three months ended September 30, 2008 as compared to other income of approximately $1.2 million during the same period in 2007, a decrease in other income of approximately $2.3 million, primarily due to a loss on the guaranteed flat bill tariff due to warmer than normal weather with more customers participating in this plan.

 

Other Expense. Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $0.6 million during the three months ended September 30, 2008 as compared to approximately $3.3 million during the same period in 2007, a decrease of approximately $2.7 million, or 81.8 percent, primarily due to a write-off in 2007 related to the cancelled Red Rock power plant project.

 

Interest Expense. Interest expense was approximately $18.7 million during the three months ended September 30, 2008 as compared to approximately $16.0 million during the same period in 2007, an increase of approximately $2.7 million, or 16.9 percent, primarily due to:

 

 

 

 

Income Tax Expense. Income tax expense was approximately $43.8 million during the three months ended September 30, 2008 as compared to approximately $51.9 million during the same period in 2007, a decrease of approximately $8.1 million, or 15.6 percent, primarily due to lower pre-tax income in the third quarter of 2008 as compared to the same period in 2007 as well as a lower overall effective income tax rate primarily due to an increase in Federal renewable energy credits and additional state income tax credits in the third quarter of 2008 as compared to the same period in 2007.

 

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

 

OG&E’s operating income decreased approximately $21.7 million during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to higher operating expenses, higher depreciation and amortization expense and higher taxes other than income partially offset by a higher gross margin.

 

 

These increases in the gross margin were partially offset by the reversal of the Kaiser-Francis take-or-pay litigation reserve, which increased the 2007 gross margin by approximately $4.0 million.

 

Fuel expense was approximately $719.6 million during the nine months ended September 30, 2008 as compared to approximately $568.0 million during the same period in 2007, an increase of approximately $151.6 million, or 26.7 percent, primarily due to higher natural gas prices. Purchased power costs were approximately $214.1 million during the nine months ended September 30, 2008 as compared to approximately $195.6 million during the same period in 2007, an increase of approximately $18.5 million, or 9.5 percent, primarily due to purchasing more MWHs and higher prices in 2008 as compared to the same period in 2007.

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $260.0 million during the nine months ended September 30, 2008 as compared to approximately $230.8 million during the same period in 2007, an increase of approximately $29.2 million, or 12.7 percent. The increase in other operation and maintenance expenses was primarily due to:

 

 

These increases in other operation and maintenance expenses were partially offset by a decrease of approximately $4.1 million due to a lower provision for uncollectible accounts receivable.

 

Depreciation expense was approximately $110.9 million during the nine months ended September 30, 2008 as compared to approximately $105.3 million during the same period in 2007, an increase of approximately $5.6 million, or 5.3 percent, primarily due to additional assets being placed into service.

 

Taxes other than income were approximately $44.9 million during the nine months ended September 30, 2008 as compared to approximately $42.3 million during the same period in 2007, an increase of approximately $2.6 million, or 6.1 percent, primarily due to higher ad valorem and payroll taxes.

 

Additional Information

 

Interest Income. Interest income was approximately $2.7 million during the nine months ended September 30, 2008. There was no interest income during the same period in 2007. The increase in interest income was primarily due to interest from customers related to the fuel under recovery balance during the nine months ended September 30, 2008.

 

 

 

These increases in other expense were partially offset by a write-off of approximately $2.2 million associated with the Red Rock power plant for the Arkansas and the FERC jurisdictions during the third quarter of 2007.

 

Interest Expense. Interest expense was approximately $55.2 million during the nine months ended September 30, 2008 as compared to approximately $48.1 million during the same period in 2007, an increase of approximately $7.1 million, or 14.8 percent. The increase in interest expense was primarily due to:

 

 

 

 

Income Tax Expense. Income tax expense was approximately $49.6 million during the nine months ended September 30, 2008 as compared to approximately $66.7 million during the same period in 2007, a decrease of approximately $17.1 million, or 25.6 percent, primarily due to lower pre-tax income during the first nine months of 2008 as compared to the same period in 2007 as well as a lower overall effective income tax rate primarily due to an increase in Federal renewable energy credits and additional state income tax credits in the third quarter of 2008 as compared to the same period in 2007.

 

Enogex

 

 

 

 

 

 

 

Operating Data

(A) Includes wells behind central receipt points (as reported to management by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site.

 

 

(B) Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.

(C) The estimated realized keep-whole spread is an approximation of the spread between the weighted-average sales price of the retained NGL commodities and the purchase price of the replacement natural gas shrink. The spread is based on the market commodity spread less any gains or losses realized from keep-whole hedging transactions. The market commodity spread is estimated using the weighted-average OPIS daily posting for the NGL commodities prices and the Inside FERC Panhandle Eastern Pipe Line Co. TX and OK first of the month posting for natural gas prices.

 

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

 

Operating Income

 

Enogex’s operating income increased approximately $15.8 million during the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to a higher gross margin in both the gathering and processing business and the transportation and storage business partially offset by higher operating expenses in both segments.

 

Gross Margin

 

Enogex’s consolidated gross margin increased approximately $22.5 million during the three months ended September 30, 2008 as compared to the same period in 2007. The increase resulted from a $16.0 million higher gross margin in the gathering and processing business and an $8.2 million higher gross margin in the transportation and storage business. Gross margin during the three months ended September 30, 2007 included approximately $2.6 million attributable to OERI.

 

The transportation and storage business contributed approximately $46.0 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008 as compared to approximately $37.8 million during the same period in 2007, an increase of approximately $8.2 million, or 21.7 percent. The transportation operations contributed approximately $39.0 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008. The storage operations contributed approximately $7.0 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008. The transportation and storage gross margin increased primarily due to:

 

 

These increases in the transportation and storage business were partially offset by an increase in Enogex’s over-recovered position in the East Zone in its transportation operations during the three months ended September 30, 2008, with no corresponding activity during the same period in 2007, which decreased the gross margin by approximately $4.3 million.

 

The gathering and processing business contributed approximately $62.2 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008 as compared to approximately $46.2 million during the same period in 2007, an increase of approximately $16.0 million, or 34.6 percent. The gathering operations contributed approximately $20.1 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008. The processing operations contributed approximately $42.1 million of Enogex’s consolidated gross margin during the three months ended September 30, 2008. The gathering and processing gross margin increased primarily due to:

 

 

 

 

 

 

These increases in the gathering and processing business were partially offset by:

 

 

Operating Expenses

 

The aggregate of other operation and maintenance expenses, depreciation and amortization expense, impairment of assets and taxes other than income was approximately $6.7 million higher during the three months ended September 30, 2008 as compared to the same period in 2007. The variances in depreciation and amortization on both a consolidated basis and by segment reflect increased levels of depreciable plant in service during 2008. The $4.3 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to an increase in salaries, wages and benefits during the three months ended September 30, 2008 as compared to the same period in 2007.

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $1.6 million, or 15.0 percent, higher during the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to higher salaries, wages and other employee benefits expense of approximately $2.1 million primarily due to higher incentive compensation and hiring additional employees to support business growth.

 

These increases in other operation and maintenance expense were partially offset by higher internal allocations for overhead costs of approximately $1.0 million to the other Enogex segments, which decreased operation and maintenance expenses for the transportation and storage segment.

 

Other operation and maintenance expenses for the gathering and processing business were approximately $4.2 million, or 23.3 percent, higher during the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to higher allocations for overhead and labor costs from the transportation and storage segment of approximately $2.3 million during the three months ended September 30, 2008.

 

Other operation and maintenance expenses for the marketing business were approximately $2.4 million during the three months ended September 30, 2007.

 

Enogex Consolidated Information

 

Interest Income. Enogex consolidated interest income was approximately $0.4 million during the three months ended September 30, 2008 as compared to approximately $2.1 million during the same period in 2007, a decrease of approximately $1.7 million, or 81.0 percent, primarily due to a decrease in interest earned as the balance of advances to OGE Energy decreased due to dividends and capital expenditures.

 

 

 

Other Expense. Enogex’s consolidated other expense was approximately $2.0 million during the three months ended September 30, 2008 as compared to approximately $0.2 million during the same period in 2007, an increase of approximately $1.8 million, primarily due to an increase in the minority interest in the earnings of the Atoka joint venture, which began operations in August 2007.

 

Income Tax Expense. Enogex consolidated income tax expense was approximately $17.8 million during the three months ended September 30, 2008 as compared to approximately $13.3 million during the same period in 2007, an increase of approximately $4.5 million, or 33.8 percent, primarily due to higher pre-tax income in the third quarter of 2008 as compared to the same period in 2007.

 

Timing Items. For the three months ended September 30, 2007, Enogex’s consolidated net income was approximately $20.4 million which included a loss of approximately $2.9 million resulting from recording economic hedges associated with various transportation contracts held by OERI at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2007. Also, for the three months ended September 30, 2007, OERI recorded losses totaling 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 were realized during the remainder of 2007 and the first three months of 2008.

 

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

 

Enogex’s operating income increased approximately $40.2 million during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to a higher gross margin in both the gathering and processing business and the transportation and storage business partially offset by higher operating expenses in both segments.

 

Gross Margin

 

Enogex’s consolidated gross margin increased approximately $59.9 million during the nine months ended September 30, 2008 as compared to the same period in 2007. The increase resulted from a $71.8 million higher gross margin in the gathering and processing business and a $6.8 million higher gross margin in the transportation and storage business. Gross margin during the nine months ended September 30, 2007 included approximately $21.2 million attributable to OERI.

 

The transportation and storage business contributed approximately $114.8 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008 as compared to approximately $108.0 million during the same period in 2007, an increase of approximately $6.8 million, or 6.3 percent. The transportation operations contributed approximately $92.5 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008. The storage operations contributed approximately $22.3 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008. The transportation and storage gross margin increased primarily due to:

 

 

 

 

 

 

 

 

The gathering and processing business contributed approximately $200.5 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008 as compared to approximately $128.7 million during the same period in 2007, an increase of approximately $71.8 million, or 55.8 percent. The gathering operations contributed approximately $66.3 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008. The processing operations contributed approximately $134.2 million of Enogex’s consolidated gross margin during the nine months ended September 30, 2008. The gathering and processing gross margin increased primarily due to:

 

 

These increases in the gathering and processing business are partially offset by:

 

 

Operating Expenses

 

The aggregate of other operation and maintenance expenses, depreciation and amortization expense, impairment of assets and taxes other than income was approximately $19.7 million higher during the nine months ended September 30, 2008 as compared to the same period in 2007. The variances in depreciation and amortization expense on both a consolidated basis and by segment reflects increased levels of depreciable plant in service during 2008. The $13.2 million increase in other operation and maintenance expenses on a consolidated basis was primarily due to an increase in expenses for non-capitalized system projects, an increase in salaries, wages and benefits and increased allocations for overhead costs from OGE Energy and administrative service fees from OERI during the nine months ended September 30, 2008 as compared to the same period in 2007.

 

 

Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $4.0 million, or 12.1 percent, higher during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to:

 

 

These increases were partially offset by higher internal allocations for overhead costs of approximately $5.0 million to the other Enogex segments, which decreased operation and maintenance expense for the transportation and storage segment.

 

Other operation and maintenance expenses for the gathering and processing business were approximately $13.7 million, or 26.9 percent, higher during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to:

 

 

Other operation and maintenance expenses for the marketing business were approximately $7.0 million during the nine months ended September 30, 2007.

 

Enogex Consolidated Information

 

Interest Income. Enogex’s consolidated interest income was approximately $2.2 million during the nine months ended September 30, 2008 as compared to approximately $7.0 million during the same period in 2007, a decrease of approximately $4.8 million, or 68.6 percent, primarily due to a decrease in interest earned as the balance of advances to OGE Energy decreased due to dividends and capital expenditures.

 

Other Expense. Enogex’s consolidated other expense was approximately $5.8 million during the nine months ended September 30, 2008 as compared to approximately $0.2 million during the same period in 2007, an increase of approximately $5.6 million primarily due to an increase in the minority interest in the earnings of the Atoka joint venture, which began operations in August 2007.

 

Income Tax Expense. Enogex’s consolidated income tax expense was approximately $51.7 million during the nine months ended September 30, 2008 as compared to approximately $40.0 million during the same period in 2007, an increase of approximately $11.7 million, or 29.2 percent, primarily due to higher pre-tax income during the first nine months of 2008 as compared to the same period in 2007.

 

Timing Items. For the nine months ended September 30, 2007, Enogex’s consolidated net income was approximately $64.0 million, which included a loss of approximately $1.9 million resulting from recording economic hedges associated with various transportation contracts held by OERI at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2007. Also, for the nine months ended September 30, 2007, OERI recorded losses totaling 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 were realized during the remainder of 2007 and the first three months of 2008.

 

Enogex’s Non-GAAP Financial Measures

 

Enogex has included in this Form 10-Q the non-GAAP financial measure EBITDA. Enogex defines EBITDA as net income before interest, income taxes and depreciation. EBITDA is used as a supplemental financial measure by external users of the Company’s financial statements such as investors, commercial banks and others, to assess:

 

 

 

The economic substance behind the use of EBITDA is to measure the ability of Enogex’s assets to generate cash sufficient to pay interest costs, support indebtedness and pay dividends to OGE Energy.

 

Enogex provides a reconciliation of EBITDA to its most directly comparable financial measures as calculated and presented in accordance with generally accepted accounting principles (“GAAP”). The GAAP measures most directly comparable to EBITDA are net cash provided from operating activities and net income. The non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided from operating activities and GAAP net income. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. EBITDA should not be considered in isolation or as a substitute for analysis of Enogex’s results as reported under GAAP. Because EBITDA excludes some, but not all, items that affect net income and net cash provided from operating activities and is defined differently by different companies in Enogex’s industry, Enogex’s definition of EBITDA may not be comparable to similarly titled measures of other companies.

 

To compensate for the limitations of EBITDA as an analytical tool, Enogex believes it is important to review the comparable GAAP measures and understand the differences between the measures.

 

Reconciliation of EBITDA to net cash provided from operating activities

 

Reconciliation of EBITDA to net income

There are no results for OERI included in the above tables for the three and nine months ended September 30, 2008 because, as of January 1, 2008, Enogex distributed the stock of OERI to OGE Energy.

 

 

 

 

OERI

 

 

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

 

Operating Income

 

OERI’s operating income increased approximately $6.4 million during the three months ended September 30, 2008 as compared to the same period in 2007 primarily due to a higher gross margin partially offset by higher operation and maintenance expense.

 

Gross Margin

 

Gross margin was approximately $9.2 million during the three months ended September 30, 2008 as compared to approximately $2.6 million during the same period in 2007, an increase of approximately $6.6 million. The gross margin increased primarily due to:

 

 

These increases in the gross margin were partially offset by:

 

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $2.7 million during the three months ended September 30, 2008 as compared to approximately $2.4 million during the same period in 2007, an increase of approximately $0.3 million, or 12.5 percent, primarily due to higher allocations from OGE Energy and its affiliates.

 

 

 

Additional Information

 

Income Tax Expense. Income tax expense was approximately $2.6 million during the three months ended September 30, 2008 as compared to approximately $0.1 million during the same period in 2007, an increase of approximately $2.5 million, primarily due to higher pre-tax income in the third quarter of 2008 as compared to the same period in 2007.

 

Timing Items. For the three months ended September 30, 2008, OERI’s net income was approximately $4.0 million, which included a net loss of approximately $0.9 million resulting from recording hedges associated with various transportation contracts at market value on September 30, 2008. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2008.

 

For the three months ended September 30, 2007, OERI’s net income was approximately $0.3 million, which included a loss of approximately $2.9 million resulting from recording economic hedges associated with various transportation contracts held by OERI at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2007. Also, for the three months ended September 30, 2007, OERI recorded losses totaling 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 were realized during the remainder of 2007 and the first three months of 2008.

 

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

 

Operating Income

 

OERI’s operating income decreased approximately $12.1 million during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily due to a lower gross margin and higher operation and maintenance expense.

 

Gross Margin

 

Gross margin was approximately $10.4 million during the nine months ended September 30, 2008 as compared to approximately $21.2 million during the same period in 2007, a decrease of approximately $10.8 million, or 50.9 percent. The gross margin decreased primarily due to:

 

 

These decreases in the gross margin were partially offset by gains on economic storage hedges from recording these hedges at market value on September 30, 2008 as compared to losses from recording these hedges at market value on September 30, 2007, which increased the gross margin by approximately $12.6 million.

 

Operating Expenses

 

Other operation and maintenance expenses were approximately $8.4 million during the nine months ended September 30, 2008 as compared to approximately $7.0 million during the same period in 2007, an increase of approximately $1.4 million, or 20.0 percent, primarily due to higher allocations from OGE Energy and its affiliates.

 

 

 

Additional Information

 

Income Tax Expense. Income tax expense was approximately $0.9 million during the nine months ended September 30, 2008 as compared to approximately $5.5 million during the same period in 2007, a decrease of approximately $4.6 million, or 83.7 percent, primarily due to lower pre-tax income during the first nine months of 2008 as compared to the same period in 2007.

 

Timing Items. For the nine months ended September 30, 2008, OERI’s net income was approximately $1.3 million, which included a net loss of approximately $1.7 million resulting from recording hedges associated with various transportation contracts at market value on September 30, 2008. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2008.

 

For the nine months ended September 30, 2007, OERI’s net income was approximately $8.7 million, which included a loss of approximately $1.9 million resulting from recording economic hedges associated with various transportation contracts held by OERI at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2007. Also, for the nine months ended September 30, 2007, OERI recorded losses totaling 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 were realized during the remainder of 2007 and the first three months of 2008.

 

Financial Condition

 

The balance of Cash and Cash Equivalents was approximately $204.9 million and $8.8 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $196.1 million primarily due to the need for the Company to have adequate liquidity due to the volatility of the commercial paper and capital markets.

 

The balance of Accounts Receivable was approximately $375.0 million and $334.4 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $40.6 million, or 12.1 percent, primarily due to an increase in OG&E’s billings to its customers reflecting high seasonal rates in September as compared to December partially offset by a decrease in natural gas prices and volumes at OERI.

 

The balance of Fuel Inventories was approximately $98.1 million and $82.0 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $16.1 million, or 19.6 percent, primarily due to an increased balance in natural gas inventory at OG&E from higher prices and volumes.

 

The balance of Fuel Clause Under Recoveries was approximately $109.9 million and $27.3 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $82.6 million, primarily due to the fact the amount billed to Oklahoma retail customers was lower than the Company’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

 

The balance of Property, Plant and Equipment in Service was approximately $7.6 billion and $6.8 billion at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $0.8 billion, or 11.8 percent, primarily due to the purchase of the Redbud Facility as well as other projects for transmission and distribution at OG&E and various gathering and transportation projects at Enogex.

 

The balance of Construction Work in Process was approximately $266.3 million and $179.8 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $86.5 million, or 48.1 percent, primarily due to costs associated with a new wind generating facility near Woodward, Oklahoma and various transportation, gathering and processing projects at Enogex.

 

The balance of Prepaid Pension Obligation was approximately $41.2 million at September 30, 2008. There was no balance at December 31, 2007. The increase was primarily due to a reclassification from Accrued Benefit Obligations to Prepaid Pension Obligation due to contributions made for the funding of the pension plan.

 

The balance of Short-Term Debt was approximately $739.8 million and $295.8 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $444.0 million, primarily due to increased commercial paper

 

 

 

 

borrowings related to higher fuel costs, capital expenditures, pension plan contributions, dividend payments, purchase of the Redbud Facility and other daily operational needs of the Company.

 

The balance of Accounts Payable was approximately $232.1 million and $399.3 million at September 30, 2008 and December 31, 2007, respectively, a decrease of approximately $167.2 million, or 41.9 percent, primarily due to a decrease in cash overdrafts and payments made in the first quarter 2008 for the December 2007 ice storm and a decrease in volumes purchased from third parties at OERI.

 

The balance of Accrued Compensation was approximately $38.1 million and $53.9 million at September 30, 2008 and December 31, 2007, respectively, a decrease of approximately $15.8 million, or 29.3 percent, primarily due to the annual payment for incentive compensation made in the first quarter of 2008 and less accrued salaries and wages at September 2008 compared to December 2007.

 

The balance of Other Current Liabilities was approximately $56.8 million and $38.2 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $18.6 million, or 48.7 percent, primarily due to an increase in the weighted-average cost of an inventory valuation under a certain storage agreement at OERI.

 

The balance of Long-Term Debt was approximately $1.9 billion and $1.3 billion at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $0.6 billion, or 46.2 percent, primarily due to the issuance of long-term debt by OG&E in the first and third quarters of 2008.

 

The balance of Accumulated Deferred Income Taxes was approximately $995.6 million and $853.6 million at September 30, 2008 and December 31, 2007, respectively, an increase of approximately $142.0 million, or 16.6 percent, primarily due to accelerated tax depreciation resulting from the impact of the bonus depreciation provisions contained in the Economic Stimulus Act of 2008 related to assets placed into service during 2008.

 

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 Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 Form 10-K”).

 

OG&E Railcar Lease Agreement

 

At December 31, 2007, OG&E had a noncancellable operating lease with purchase options, covering 1,409 coal hopper railcars to transport coal from Wyoming to OG&E’s coal-fired generation units. In April 2008, OG&E amended its contract to add 55 new railcars for approximately $3.5 million. At the end of the new lease term, which is January 31, 2011, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of approximately $31.5 million.

 

Liquidity and Capital Requirements

 

The Company’s primary needs for capital through the end of 2009 are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex. Other working capital requirements through the end of 2009 are expected to be primarily related to hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes. The Company has no maturing debt through the end of 2009. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. However, 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. 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.

 

 

At September 30, 2008 and October 15, 2008, the Company had approximately $204.9 million and $365.3 million, respectively, of cash on hand. At September 30, 2008 and October 15, 2008, the Company had approximately $575.0 million and $525.0 million, respectively, of net availability liquidity under its revolving credit agreements and term loan agreement.

 

Cash Flows

 

The reduction of approximately $66.4 million in net cash provided from operating activities during the nine months ended September 30, 2008 as compared to the same period in 2007 was primarily due to: (i) an increase in accounts receivable primarily due to warmer weather and higher fuel prices in 2008 as compared to the same period in 2007, (ii) an increase in fuel inventories and materials and supplies inventories primarily due to higher fuel prices and higher quantities, (iii) an increase in fuel clause under recoveries due to higher fuel costs versus billed fuel revenues in 2008, (iv) a decrease in fuel clause over recoveries due to higher billed fuel revenues versus actual costs in 2007, (v) a decrease in accrued taxes due to the current tax provision, settlement of prior year tax liabilities from filing of returns and payments related to IRS audit settlements and (vi) a decrease in price risk management assets, which was partially offset by an increase in price risk management liabilities. The increase of approximately $542.8 million in net cash used in investing activities during the nine months ended September 30, 2008 as compared to the same period in 2007 related to higher level of capital expenditures primarily related to the purchase of the Redbud Facility and a higher level of capital expenditures at Enogex. The increase of approximately $851.2 million in net cash provided from financing activities during the nine months ended September 30, 2008 as compared to the same period in 2007 primarily related to proceeds received from the issuance of long-term debt in January and September 2008, an increase in short-term debt primarily due to higher fuel costs and higher levels of capital expenditures and an increase in proceeds from the line of credit primarily related to Enogex capital expenditures and the payment of a dividend to OGE Energy.

 

Future Capital Requirements

 

Capital Expenditures

 

The Company’s current 2008 to 2013 construction program includes continued investment in OG&E’s distribution, generation and transmission system and Enogex’s transportation, storage, gathering and processing assets. In the Company’s 2007 Form 10-K, the Company’s estimates of capital expenditures were approximately: 2008 - $1.1 billion, 2009 - $613.9 million, 2010 - $668.1 million, 2011 - $653.4 million, 2012 - $670.8 million and 2013 - $654.1 million. These estimates included approximately $12.0 million, $22.5 million, $83.0 million, $97.3 million, $93.8 million and $69.6 million, respectively, for environmental expenditures associated with Best Available Retrofit Technology (“BART”) requirements. As discussed in Note 12 of Notes to Condensed Consolidated Financial Statements, due to an opinion from the U.S. Environmental Protection Agency (“EPA”) that OG&E’s proposed initial compliance plan would not satisfy the applicable requirements, OG&E completed additional analysis. As required by the Oklahoma Department of Environmental Quality (“ODEQ”), OG&E completed additional analysis and, on May 30, 3008, filed with the ODEQ the results of its BART evaluation for the affected generating units as well as withdrawing its alternative plan filed in March 2007. In the May 30, 2008 filing, OG&E indicated its intention to install low nitrogen oxide (“NOX”) combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. OG&E believes that these control measures will achieve visibility improvements in a cost-effective manner. OG&E did not propose the installation of scrubbers at its four coal-fired generating units because OG&E concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. The Company cannot predict what action the EPA or the ODEQ will take in response to OG&E’s May 30, 2008 filing. OG&E expects that a compliance plan will be approved by the EPA by December 31, 2008. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by OG&E with a reasonable degree of certainty. Due to this uncertainty regarding BART costs, the Company has excluded any BART costs from its updated capital expenditure estimates. Therefore, the Company’s current estimates of capital expenditures, without any BART costs, are approximately: 2008 - $1.2 billion (approximately $434.5 million are related to the acquisition of the Redbud Facility), 2009 - $893 million, 2010 - $654 million, 2011 - $689 million, 2012 - $728 million and 2013 - $767 million. These capital expenditures include expenditures related to: (i) the proposed transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma, (ii) OGE Energy’s portion of the proposed transmission  

 

projects as part of a newly formed transmission joint venture and (iii) OG&E’s proposed wind power project. These capital expenditures exclude expenditures related to the proposed joint venture with ETP.

 

Pension Plan Funding

 

In the third quarter of 2008, the Company contributed approximately $10 million to its pension plan for a total contribution of $50 million to its pension plan during 2008. No additional contributions are expected in 2008.

 

SPP Letter of Credit

 

On October 31, 2006, OG&E submitted a commercial letter of credit to the SPP for approximately $2.9 million related to the costs of upgrades required for OG&E to obtain transmission service from its new Centennial wind farm. The amount of this letter of credit was reduced each year as payments were made for transmission service.  On August 4, 2008, this letter of credit was cancelled and is no longer required due to the determination that the upgrades required to grant the transmission request relating to the Centennial wind farm will receive full base plan funding.

 

Future Sources of Financing

 

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

 

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. The Company expects to issue equity when market conditions are favorable.

 

Issuance of New Long-Term Debt

 

In September 2008, OG&E issued $250 million of 6.35% senior notes due September 1, 2018. The proceeds from the issuance were used to fund a portion of the acquisition of the Redbud Facility. Pending such use, the proceeds were used to temporarily repay a portion of OG&E’s outstanding commercial paper borrowings, as well as short-term borrowings from OGE Energy, both of which were incurred in part to fund OG&E’s daily operational needs. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable.

 

Short-Term Debt

 

Short-term borrowings generally are used to meet working capital requirements. At September 30, 2008, the Company had approximately $859.8 million in outstanding borrowings under its revolving credit agreements. At December 31, 2007, the Company had approximately $295.0 million in outstanding commercial paper borrowings. 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. 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. 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.

 

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 effect 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 2007 Form 10-K.

 

Accounting Pronouncements

 

See Notes 2 and 3 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 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 and in the Company’s 2007 Form 10-K, 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 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the 2007 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 2007 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 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 20 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, 2008.

 

 

Non-Trading Activities

 

The prices of natural gas, NGLs and NGLs 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 Company’s 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.

 

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 forward prices curves.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 20 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, 2008.

 

 

Management 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 NGLs produced by its subsidiary, Enogex Products LLC; (iii) electric power contracts by OG&E; and (iv) fuel procurement by OG&E.

 

Credit Risk

 

Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.

 

For Enogex and OERI, credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. Enogex and OERI maintain credit policies with regard to its counterparties that management believes minimize overall credit risk. These policies include the evaluation of a potential counterparty’s financial position (including credit rating, if available), collateral requirements under certain circumstances and the use of standardized agreements which provide for the netting of cash flows associated with a single counterparty. Enogex and OERI also monitor the financial position of existing counterparties on an ongoing basis.

 

 

 

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 2007 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.        Franchise Fee Lawsuit. On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law.  OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.   In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges. Motions to set a procedural schedule and determine notice requirements for the matter are scheduled to be heard by the OCC on November 6, 2008.  OG&E believes that this case is without merit.

 

     2.             Oxley Litigation. OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs’ alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs’ in amounts set forth in the contracts.  The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. OG&E expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

 

Item 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 2007 Form 10-K.

 

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.

 

We cannot assure that any of our current ratings or the ratings of our subsidiaries’ will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the market turmoil in September and October 2008. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit. Also, any downgrade below investment grade at OERI could require us to issue guarantees to support some of OERI’s marketing operations.  

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

We have revolving credit agreements for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:

 

 

The completion of the joint venture with ETP is subject to numerous conditions and no assurances can be made that it will be successfully completed.

 

Consummation of the joint venture transaction is conditioned on antitrust approval, receipt of certain third-party consents and certain other customary closing conditions. The transaction is also conditioned upon obtaining financing pursuant to a specified financing plan that would provide funding for payments from ETP Enogex to us and ETP at the closing of the transaction as well as other financings for ETP Enogex to provide longer-term credit capacity. Specifically, the financing plan (the “Financing Plan”) specifies that (a) ETP Enogex would, at a minimum, enter into a $700 million senior secured revolving credit facility, (b) ETP Enogex would issue approximately $800 million of senior unsecured notes and (c) Transwestern would issue approximately $800 million in senior unsecured notes. Each of the parties have agreed that, as a condition to the parties’ obligations to consummate the transaction, the terms of the Financing Plan must be at least as favorable to ETP Enogex as certain agreed upon terms, which we believe approximate existing market terms. There can be no assurances that the Financing Plan or the other closing conditions will be satisfied or that the joint venture will be successfully completed.

 

Pursuant to a contribution agreement, we will contribute 100 percent of our ownership interest in Enogex to ETP Enogex. ETP will contribute 100 percent of its ownership interest in the Transwestern pipeline, 100 percent of its ownership

 

 

If the joint venture is not able to obtain adequate financing, we may need to provide in cash our respective share of capital expenditure requirements for ETP Enogex.

 

If the joint venture is not able to obtain adequate financing on favorable terms, we and ETP, as 50 percent owners of ETP Enogex, may be required to contribute additional funds to support ETP Enogex’s capital expenditure programs.

 

 

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

 

 

 

 

 

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.

 

 

 

 

October 31, 2008