(Mark One)

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

 

 

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

 

 

 

 

 

 

 

 

 

 

 

 

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, 2008 (“2008 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.

 

 

 

 

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

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

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

 

 

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

 

 

 

 

 

 

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

 

4

 

 

 

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

 

                                            5

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

6

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 natural gas business in 1928 and is no longer engaged in the natural 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 operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing. Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly owned subsidiary of Enogex.

 

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 owns 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 Company charges 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 Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

 

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2009 and December 31, 2008, the results of its operations for the three months ended March 31, 2009 and 2008, and the results of its cash flows for the three months ended March 31, 2009 and 2008, 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 months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009 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 Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 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 the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” 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.

 

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 Accounting Principles Board (“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 (“PRM”) assets and liabilities would be approximately $51.9 million and $48.2 million, respectively, at March 31, 2009, and non-current Price Risk Management assets and liabilities would be approximately $82.4 million and $42.7 million, respectively, at March 31, 2009. 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 $51.8 million and $35.4 million, respectively, at December 31, 2008, and non-current Price Risk Management assets and liabilities would be approximately $105.6 million and $36.2 million, respectively, at December 31, 2008.

 

Reclassifications

 

Certain prior year amounts have been reclassified on the Condensed Consolidated Financial Statements to conform to the 2009 presentation related to the separate presentation of noncontrolling interests in a subsidiary in connection with the adoption of SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” as discussed in Note 2.

 

 

In December 2007, the FASB issued SFAS No. 160 which is intended to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations. SFAS No. 160 amends Accounting Research Bulletin (“ARB”) No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 also amends certain of ARB No. 51’s consolidation procedures for consistency with the requirements of SFAS No. 141(R), “Business Combinations.” SFAS No. 160 was effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The provisions of SFAS No. 160 are to be applied prospectively as of the beginning of the fiscal year in which it is initially adopted, except for the presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. The Company adopted this new standard effective January 1, 2009. The adoption of this new standard changed the presentation of noncontrolling interests in the Company’s consolidated financial statements for the Atoka joint venture.

 

In February 2008, the FASB issued FASB Staff Position (“FSP”) No. 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of SFAS No. 157, “Fair Value Measurements,” for nonfinancial assets and liabilities measured on a nonrecurring basis to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The provisions of this FSP should be applied prospectively. The Company adopted this new FSP effective January 1, 2009. The adoption of this new FSP did not impact the Company as the Company does not currently have any nonfinancial assets and liabilities measured on a nonrecurring basis.

 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which required enhanced disclosures about an entity’s derivative and hedging activities and was intended to improve the transparency of financial reporting (see Note 4 for a further discussion).

 

In June 2008, the FASB issued FSP No. Emerging Issues Task Force (“EITF”) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share (“EPS”) pursuant to the two-class method described in SFAS No. 128, “Earnings per Share.” This FSP was effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. All prior-period EPS data presented should be adjusted retrospectively. The Company adopted this new FSP effective January 1, 2009. The adoption of this new FSP did not impact the Company’s EPS information as the Company already considered the restricted stock it had previously granted as a participating security and, therefore, included it in the EPS calculation.

 

In November 2008, the EITF reached a consensus and issued EITF Issue No. 08-6, “Equity Method Investment Accounting Considerations,” which applies to all investments accounted for under the equity method. EITF Issue No. 08-6 requires an entity: (i) to measure its equity method investment at cost in accordance with SFAS No. 141(R), (ii) to recognize

 

other-than-temporary impairments of an equity method investment in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” and (iii) to account for a share issuance by an investee as if the investor had sold a proportionate share of its investment with any gain or loss to the investor resulting from an investee’s share issuance being recognized in earnings. EITF Issue No. 08-6 was effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. The provisions of EITF Issue No. 08-6 are to be applied prospectively. The Company adopted this new EITF effective January 1, 2009. The adoption of this new EITF did not have a material impact on the Company’s consolidated financial position or results of operations.

 

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which applies to all assets and liabilities within the scope of accounting pronouncements that require or permit fair value measurements, except as discussed in paragraphs 2 and 3 of SFAS No. 157. This FSP requires that in order to determine fair value, an entity should evaluate factors to determine whether there has been a significant decrease in the volume and level of activity for the asset or liability when compared with normal market activity for the asset or liability. If the entity concludes there has been a significant decrease, transactions or quoted prices may not be determinative of fair value and further analysis of the transactions or quoted prices would be needed. This FSP also reaffirmed that even if there has been a significant decrease as discussed above, fair value is the price to sell an asset or transfer a liability in an orderly transaction under current market conditions. Also, this FSP requires an entity to evaluate the circumstances to determine whether the transaction is orderly (i.e. not distressed or forced) based on the weight of the evidence obtained. In addition, an entity is expected to have sufficient information to conclude whether a transaction is orderly when it is party to the transaction. This FSP amends SFAS No. 157 to require that an entity disclose in its interim and annual periods the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period. This FSP is effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. Early adoption of this FSP is permitted for periods ending after March 15, 2009 to the extent an entity also early adopts the FSP discussed below and the recently issued FSP related to other-than-temporary impairments. The Company adopted this new FSP effective April 1, 2009. The adoption of this new FSP is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

 

In April 2009, the FASB issued FSP No. FAS 107-1 and APB Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which applies to all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and requires entities to include disclosures about the fair value of its financial instruments with the related carrying amount. An entity is also required to disclose the methods and significant assumptions used to estimate the fair value of financial instruments and shall describe changes in methods and significant assumptions, if any, during the period. This FSP is effective for interim periods ending after June 15, 2009. Early adoption of this FSP is permitted for periods ending after March 15, 2009 to the extent an entity also early adopts FAS 157-4 above and the recently issued FSP related to other-than-temporary impairments. The provisions of this FSP do not require disclosures for earlier periods presented for comparative purposes at initial adoption. The Company adopted this new FSP effective April 1, 2009. The adoption of this new FSP will require disclosures about the fair value of financial instruments for interim periods in the Company’s consolidated financial statements similar to what was reported in the Company’s 2008 Form 10-K.

 

 

In September 2006, the FASB issued SFAS No. 157 which defined fair value, established a framework for measuring fair value in generally accepted accounting principles and established a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. SFAS No. 157 expanded disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” at initial recognition and in all subsequent periods. The Company adopted this 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.

 

(A) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $9.9 million, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

 

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 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 & Poor’s Ratings Services (“Standard & Poor’s”) 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 March 31, 2009 and December 31, 2008.

 

 

The following table is a summary of the Company’s assets 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 months ended March 31, 2009 attributable to the change in unrealized gains or losses relating to assets held at March 31, 2009, 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, 2008.

 

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s hedging and energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market

 

values. The valuation of instruments also considers the credit risk of the counterparties. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

 

 

In March 2008, the FASB issued SFAS No. 161 which required enhanced disclosures about an entity’s derivative and hedging activities and was intended to improve the transparency of financial reporting. SFAS No. 161 applies to all entities. SFAS No. 161 applies to all derivative instruments, including bifurcated derivative instruments and related hedging items accounted for under SFAS No. 133 and its related interpretations. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this standard do not require disclosures for earlier periods presented for comparative purposes at initial adoption. SFAS No. 161 was effective for fiscal years and interim periods beginning after November 15, 2008. The Company adopted this new standard effective January 1, 2009. The adoption of this new standard changed the disclosure related to derivative and hedging activities in the Company’s consolidated financial statements.

 

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.

 

Commodity Price Risk

 

The Company primarily uses commodity price futures, commodity price swap contracts and commodity price option features to manage the Company’s commodity price risk exposures. The commodity price futures and commodity price swap contracts involve the exchange of fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. The commodity price option contracts involve the payment of a premium for the right, but not the obligation, to exchange fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. Commodity derivative instruments used by the Company are as follows:

 

 

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement discussed above as normal purchases and normal sales contracts under the provisions of SFAS No. 133. 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 treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by its operations; (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.

 

In accordance with SFAS No. 133, the Company recognizes its non-exchange traded derivative instruments as Price Risk Management assets or liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

 

Interest Rate Risk

 

The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, the Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates.

 

Credit Risk

 

The Company is exposed to certain credit risks relating to its ongoing business operations. 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 OG&E, new business customers are required to provide a security deposit in the form of cash, a bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

 

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.

 

Cash Flow Hedges

 

For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method prescribed by SFAS No. 133. Under the change in fair value method, the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

 

At March 31, 2009, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.

 

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s contractual length and operational storage natural gas, keep-whole natural gas and NGLs hedges.  Enogex’s cash flow hedging activity at March 31, 2009 covers the period from April 1, 2009 through 2011.  The Company also designates certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at OERI. OERI’s cash flow hedging activity at March 31, 2009 does not extend beyond the first quarter of 2010. At March 31, 2009, the Company had the following outstanding commodity derivative instruments that were designated as cash flow hedges.

 

 

 

 

 

Fair Value Hedges

 

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

 

At March 31, 2009, the Company had no outstanding commodity derivative instruments or treasury lock agreements that were designated as fair value hedges.

 

Derivatives Not Designated As Hedging Instruments Under SFAS No. 133

 

For derivative instruments that are not designated as either a cash flow or fair value hedge, the gain or loss on the derivative is recognized currently in earnings. Derivative instruments not designated as either a cash flow or a fair value hedge are utilized in OERI’s marketing and trading activities.

 

At March 31, 2009, the Company had the following outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.

 

 

 

 

 

 

 

(A) Natural gas in MMBtu; NGLs in barrels. All volumes are presented on a gross basis.

(B) Of the natural gas physical purchases and sales volumes not designated as cash flow or fair value hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The fair value of the derivative instruments that are presented in the Company’s Condensed Consolidated Balance Sheet at March 31, 2009 are as follows:

    

Credit-Risk Related Contingent Features in Derivative Instruments

 

In the event Moody’s Investors Service or Standard & Poor’s were to lower the Company’s senior unsecured debt rating to a below investment grade rating, at March 31, 2009, the Company would have been required to post approximately $14.8 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at March 31, 2009.

 

 

 

 

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended March 31, 2009.

 

  (A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at   March 31, 2009 that is expected to be reclassified into earnings within the next 12 months is less than $0.1   million.

  (B) The ineffective portion of these hedges is less than $0.1 million.

 

 

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

 

The Company recorded compensation expense of approximately $1.4 million pre-tax ($0.8 million after tax, or $0.01 per basic and diluted share) and approximately $1.1 million pre-tax ($0.7 million after tax, or $0.01 per basic and diluted share) during the three months ended March 31, 2009 and 2008, respectively, related to the Company’s share-based payments.

 

During the three months ended March 31, 2009, the Company awarded 299,453 performance units based on total shareholder return and 99,818 performance units based on earnings per share with a grant date fair value under SFAS No. 123 (Revised), “Share-Based Payment,” of $23.93 and $20.02, respectively, to certain employees of the Company and its

 

subsidiaries. Also, during the three months ended March 31, 2009, the Company converted 171,670 performance units based on a payout ratio of 135.31 percent of the target number of performance units granted in February 2006.

 

The Company issues new shares to satisfy stock option exercises and payouts of earned performance units. During the three months ended March 31, 2009, there were 162,748 shares of new common stock issued pursuant to the Company’s Plans related to payouts of earned performance units. There were no exercised stock options during the three months ended March 31, 2009; however, the Company received approximately $0.2 million during the three months ended March 31, 2008 related to exercised stock options.

 

 

The components of accumulated other comprehensive loss at March 31, 2009 and December 31, 2008 are as follows:

 

 

At both March 31, 2009 and December 31, 2008, there was no accumulated other comprehensive income related to the Company’s noncontrolling interest in the Atoka joint venture.

 

 

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. 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. This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income. In addition, OG&E earns both Federal and Oklahoma state tax credits associated with the production from its 120 megawatt (“MW”) wind farm in northwestern Oklahoma 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.

 

 

Automatic Dividend Reinvestment and Stock Purchase Plan

 

In November 2008, the Company filed a Form S-3 Registration Statement to register 5,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”). The Company issued 1,240,072 shares of common stock under the DRIP/DSPP during the three months ended March 31, 2009 and received proceeds of approximately $29.2 million. The Company may, from time to time, issue

 

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additional shares under its DRIP/DSPP to fund capital requirements or working capital needs. At March 31, 2009, there were 3,759,928 shares available to be issued under the DRIP/DSPP.

 

Equity Issuances

 

From January 1, 2009 through January 28, 2009, the Company sold 1,086,100 shares of its common stock under a previous distribution agreement with J.P. Morgan Securities Inc. (“JPMS”). The Company received net proceeds from JPMS of approximately $26.9 million during this timeframe (after the JPMS commission of approximately $0.4 million) related to the sale of the shares of the Company’s common stock. The Company added the net proceeds from the sale of the shares of its common stock to its general funds and used those proceeds for general corporate purposes, including the repayment of outstanding revolving credit borrowings or other short-term debt. On January 28, 2009, the Company provided written notice to JPMS of the Company’s intent to terminate the distribution agreement pursuant to the terms of the distribution agreement, which termination was effective on January 29, 2009.

 

Earnings Per Share

 

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

 

 

 

At March 31, 2009, the Company was in compliance with all of its debt agreements.

 

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

 

 

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

 

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 Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by loans under short-term bank facilities. The short-term debt balance was approximately $351.5 million and $298.0 million at March 31, 2009 and December 31, 2008, respectively. The following table provides information regarding the Company’s revolving credit agreements and available cash at March 31, 2009.