(Mark One)

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

 

 

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

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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”) are providers 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: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.

 

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 (“Tallgrass”) to construct high-capacity transmission line projects in western Oklahoma. The Company owns 50 percent of Tallgrass. Tallgrass is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned transmission construction. 

 

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 June 30, 2009 and December 31, 2008, the results of its operations for the three and six months ended June 30, 2009 and 2008, and the results of its cash flows for the six months ended June 30, 2009 and 2008, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after June 30, 2009 up to the date of issuance of these Condensed Consolidated Financial Statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

 

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:

 

 

In accordance with the APSC order received by OG&E in May 2009 in its Arkansas rate case, OG&E was allowed recovery of its 2006 and 2007 pension settlement costs. During the second quarter of 2009, OG&E reduced its pension expense and recorded a regulatory asset for approximately $3.2 million, which is reflected in Deferred Pension Plan Expenses in the table above.

 

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 $30.8 million and $44.1 million, respectively, at June 30, 2009, and non-current PRM assets and liabilities would be approximately $49.0 million and $30.0 million, respectively, at June 30, 2009. If these transactions with the same counterparty were presented on a gross basis in the Condensed Consolidated Balance Sheets, current PRM assets and liabilities would be approximately $51.8 million and $35.4 million, respectively, at December 31, 2008, and non-current PRM 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,” effective January 1, 2009.

 

 

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which is intended to establish principles and requirements for reporting events that occur after the balance sheet date but prior to the issuance of the financial statements. SFAS No. 165 sets forth the period after the balance sheet date during which subsequent events should be evaluated for potential recognition or disclosure in the financial statements, the circumstances under which a subsequent event shall be recognized in the financial statements and the disclosures that an entity shall make about events or transactions that occur after the balance sheet date. SFAS No. 165 separates subsequent events into two categories: (i) recognized subsequent events, which provide additional evidence about conditions that existed at the balance sheet date which should be recognized in the financial statements; and (ii) nonrecognized subsequent events, which provide evidence about conditions that arose after the balance sheet date which should not be recognized in the financial statements. SFAS No. 165 is effective for interim or annual periods ending after June 15, 2009 and should be applied on a prospective basis. The Company adopted this new standard effective June 30, 2009. As required by SFAS No. 165, the Company has evaluated subsequent events for inclusion in the financial statements through August 4, 2009, the date the financial statements were issued.

 

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets— an amendment of FASB Statement No. 140,” which is intended to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. SFAS No. 166 removes the concept of a qualifying special-purpose entity (“QSPE”) from SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,”and removes the exception from applying FIN No. 46 (Revised), “Consolidation of Variable Interest Entities,” to QSPE’s. SFAS No. 166 is effective for transfers occurring during fiscal years and interim periods within those fiscal years beginning after November 15, 2009. The Company will adopt this new standard effective January 1, 2010. The adoption of this new standard is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

 

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46 (R),” which is intended to improve financial reporting by addressing the effects on certain provisions of FIN No. 46(R) as a result of the elimination of the QSPE concept in SFAS No. 166and concerns about the application of certain key provisions of FIN No. 46(R), including those in which the accounting and disclosures do not always provide timely and useful information about entities’ involvement in a variable interest entity. SFAS No. 167 retains the scope of FIN No. 46(R) with the addition of entities previously considered QSPE’s, as the concept of these entities was eliminated in SFAS No. 166. SFAS No. 167 is effective for fiscal years and interim periods within those fiscal years beginning after November 15, 2009. The provisions of SFAS No. 167 require public entities, in periods after initial adoption, to disclose comparative information required by FASB Staff Position (“FSP”) No. FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities about Transfers of Financial Assets and Interests in Variable Interest Entities.” The Company will adopt this new standard effective January 1, 2010. The adoption of this new standard is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

 

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162,” which is intended to establish the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied to nongovernmental entities. SFAS No. 168 replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which provided the previous guidance for the organization of GAAP. SFAS No. 168 arranges guidance into two categories, authoritative and non-authoritative. All authoritative guidance contained in the Codification carries an equal level of authority. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company will adopt this new standard effective September 30, 2009.

 

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defined fair value, established a framework for measuring fair value in GAAP 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 $8.4 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 June 30, 2009 and December 31, 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 six months ended June 30, 2009 and 2008 attributable to the change in unrealized gains or losses relating to assets and liabilities held at June 30, 2009 and 2008, if any, are reported in Operating Revenues.

 

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. The Company adopted this new FSP effective April 1, 2009. 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 at June 30, 2009 and 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, “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. 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 PRM 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 PRM 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.

 

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 June 30, 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 June 30, 2009 covers the period from July 1, 2009 through 2011.  The Company also designates certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at

 

(A) Natural gas in million British thermal unit (“MMBtu”); NGLs in barrels. All volumes are presented on a gross basis.

 

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 June 30, 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 asset management, marketing and trading activities. Derivative instruments not designated as either cash flow or fair value hedges also include contracts formerly designated as cash flow hedges of Enogex’s keep-whole natural gas and NGLs exposures. A portion of Enogex’s processing agreements, which were previously under keep-whole arrangements, were converted to fee-based arrangements. As a result, effective June 30, 2009 Enogex de-designated a portion of these derivatives and entered into offsetting derivatives to close the positions.

 

 

 

 

At June 30, 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.