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EXCO Resources 10-Q 2009 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2009 OR
For the transition period from to Commission File Number 0-9204
EXCO RESOURCES, INC. (Exact name of registrant as specified in its charter)
(214) 368-2084 (Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files). YES ¨ NO ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x The number of shares of common stock, par value $0.001 per share, outstanding as of July 31, 2009 was 211,189,766.
Table of ContentsEXCO RESOURCES, INC. INDEX
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Table of Contents
CONDENSED CONSOLIDATED BALANCE SHEETS
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS
See accompanying notes.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
See accompanying notes.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
See accompanying notes.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (Unaudited)
See accompanying notes.
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Table of ContentsNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
Unless the context requires otherwise, references in this quarterly report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries. EXCO Resources, Inc., a Texas corporation, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we have midstream operations in the East Texas/North Louisiana area. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries and together they are collectively referred to as EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt. The accompanying condensed consolidated balance sheets as of June 30, 2009 and December 31, 2008, the statements of operations for the three and six months ended June 30, 2009 and 2008, the statements of cash flows for the six months ended June 30, 2009 and 2008 and the changes in shareholders’ equity for the six months ended June 30, 2009 and 2008, are for EXCO and its subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America, or GAAP, and therefore, all intercompany transactions have been eliminated. We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at June 30, 2009 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Beginning in the fourth quarter of 2008, we reclassified our derivative financial instrument activities and other income items to the other income (expense) caption on our consolidated statements of operations. Previously, we reported these items as a component of revenues. We have reclassified prior year amounts to conform to current year reporting. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.
On June 29, 2009 we entered into a definitive agreement with an affiliate of BG Group plc, or BG Group, for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which includes most of our oil and natural gas assets in East Texas/North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), and for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We will receive $655.0 million in cash at closing, subject to customary closing and post-closing adjustments, pursuant to this transaction. BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, we will not be required to repay any of this funding. The joint development transaction is expected to close in August 2009 and will have an effective date of January 1, 2009. In addition, on August 5, 2009, we entered into a definitive agreement with BG Group regarding the sale of 50% of our midstream assets in the AMI. Proceeds from the sale of the midstream assets will be $249.0 million subject to customary closing and post-closing adjustments. On June 28, 2009, EXCO Operating entered into a Purchase and Sale Agreement, or the East Texas Agreement, with Encore Operating, LP, or Encore. Pursuant to the East Texas Agreement, upon the terms and subject to the conditions set forth therein, EXCO Operating has agreed to sell all of its interests in certain oil and natural gas properties located in its Overton Field and Gladewater area of East Texas, and Encore has agreed to purchase such interests, for a purchase price of $165.0 million, in cash, subject to certain customary closing and post-closing adjustments.
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Table of ContentsAlso on June 28, 2009, EXCO entered into a Purchase and Sale Agreement, or the Mid-Continent Agreement, with Encore. Pursuant to the Mid-Continent Agreement, upon the terms and subject to the conditions set forth therein, EXCO has agreed to sell all of its interests in certain oil and gas properties located in its Mid-Continent operating area, and Encore has agreed to purchase such interests, for a purchase price of $210.0 million, in cash, subject to certain customary closing and post-closing adjustments. Both the East Texas Agreement and the Mid-Continent Agreement (together, the Encore Agreements) contain customary representations, warranties, covenants, indemnities and termination provisions and are subject to customary closing conditions with an effective date of April 1, 2009 and are expected to close in August 2009. The closing of each Encore Agreement is conditioned upon the closing of the other Encore Agreement. During the second quarter of 2009 we closed sales of certain non strategic assets, resulting in net cash proceeds of approximately $51.4 million after customary preliminary closing and post-closing adjustments. In addition to the closed sales, during the second quarter of 2009, we received deposits on pending asset sales totaling $57.7 million, of which $37.5 million is in escrow and reported as restricted cash on our condensed consolidated balance sheets. In connection with the asset sales closed in the second quarter of 2009, we liquidated certain of our derivatives contracts to stay in compliance with certain terms set forth in our credit agreements, resulting in gains of approximately $17.4 million. These gains are recorded in “Gain (loss) on derivative financial instruments” on our condensed consolidated statements of operations. A portion of the proceeds from the asset sales and derivative liquidations were used to pay down debt under our revolving credit agreements.
On June 29, 2009, the Financial Accounting Standards Board, or the FASB, issued FASB Statement No. 168, “FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a Replacement of FASB Statement No. 162,” or SFAS No. 168. SFAS No. 168 establishes “The FASB Accounting Standards Codification,” or Codification, which will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date of SFAS No. 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. SFAS No. 168 is effective for interim and annual periods ending after September 15, 2009. On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of June 30, 2009, we do not have any variable interest entities and as such, the final rule does not have an effect on our financial statements and disclosures. On June 12, 2009, the FASB issued FASB Statement No. 166, “Accounting for Transfers of Financial Assets,” or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.
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Table of ContentsOn May 28, 2009, the FASB issued FASB Statement No. 165, “Subsequent Events,” or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009. On April 9, 2009, the FASB issued Staff Position 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,” or FSP FAS 157-4. FSP FAS 157-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph 19 of FASB SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” FSP FAS 157-4 is effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures. On April 9, 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 amend Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. The staff position also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” for the impact of our disclosures. On April 1, 2009, the FASB issued FASB Staff Position No. 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1. FSP 141(R)-1 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” or SFAS No. 141, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures. On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:
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Table of ContentsWe are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.
We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of proved reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in our Annual Report on Form 10-K for the year ended December 31, 2008.
The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2009:
We have no assets that are legally restricted for purposes of settling asset retirement obligations.
The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs, which totaled $458.5 million and $481.6 million as of June 30, 2009 and December 31, 2008, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to the depletable full cost pool as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to ten years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs related to Proved Reserves are divided by the total quantities of Proved Reserves to determine the unit amortization rate. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, which is attributable to our acquisition, exploration, exploitation and development activities. Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or Proved Reserves. At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our Proved Reserves using current period-end prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). When computing our ceiling test, we evaluate the limitation at the end of each reporting period. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting period, we subsequently evaluate the limitation based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results.
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Table of ContentsFor the six months ended June 30, 2009, we recognized a ceiling test write-down of $1.3 billion to our proved oil and natural gas properties. This write-down was taken during the first quarter of 2009. There was no ceiling test write-down for the second quarter of 2009. Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On June 30, 2009, the spot price for natural gas at Henry Hub was $3.89 per Mmbtu and the spot oil price at Cushing, Oklahoma was $69.79 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. There can be no assurance that basis premiums in Appalachia will continue. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance. The pre-tax ceiling test write-down of $1.3 billion would have resulted in income tax benefits of $507.0 million for the six months ended June 30, 2009. However, we are required to establish a deferred tax valuation allowance against this tax benefit as a result of the operating losses which have resulted from such write-downs. As a result, no income tax benefit was recognized. The calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, production and changes in economics related to the properties subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
We account for earnings per share in accordance with SFAS No. 128, “Earnings per share,” or SFAS No. 128. SFAS No. 128 requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings (loss) per share for the three and six months ended June 30, 2009 and 2008 equals the net income (loss) available to common shareholders divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three and six months ended June 30, 2009 and 2008 is computed in the same manner as basic earnings (loss) per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, including our preferred stock outstanding during the first half of 2008, whether exercisable or not. Since we incurred net losses for the three and six months ended June 30, 2009 and 2008, we have excluded the potential common stock equivalents from the assumed conversion of stock options of 14,687,706 and 14,790,302 for the three and six months ended June 30, 2009, respectively, and 12,292,758 and 12,404,029 for the three and six months ended June 30, 2008, respectively, as they were antidilutive. We have also excluded 105,263,158 shares of common stock equivalents from the assumed conversion of the preferred stock from the computation of loss per share for the three and six months ended June 30, 2008, as they were antidilutive. The following table presents the basic and diluted loss per share computations:
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We account for stock options in accordance with SFAS No. 123(R), “Share-Based Compensation,” or SFAS No. 123(R). As required by SFAS No. 123(R), the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility is determined based on the combination of the weighted average volatility of our common stock price and the daily closing prices from five comparable public companies during the period when we were privately held. Total share-based compensation to be recognized on unvested awards as of June 30, 2009 is $21.6 million over a weighted average period of 1.10 years. The following is a reconciliation of our stock option expense for the three and six months ended June 30, 2009 and 2008:
During the six months ended June 30, 2009, options to purchase 178,600 shares were granted under the 2005 Incentive Plan at prices ranging from $7.89 to $16.29 per share with fair values ranging from $4.89 to $10.44 per share. During the six months ended June 30, 2008, options to purchase 832,000 shares were granted under the 2005 Incentive Plan at prices ranging from $15.15 to $27.00 per share with fair values ranging from $5.39 to $10.04 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. On June 4, 2009, our shareholders approved an amendment to the 2005 Incentive Plan to increase the number of shares authorized for issuance by an additional 3,000,000 shares. The number of shares available to be granted under the 2005 Incentive Plan as of June 30, 2009 was 6,514,575 shares. At December 31, 2008, there were 3,342,450 shares available to be granted under the 2005 Incentive Plan.
Our objective in entering into derivative financial instruments is to manage exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits we would realize if prices increase or interest rates decrease. When prices for oil and natural gas or interest rates are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We account for our derivative financial instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS No. 133. SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by SFAS No. 133 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with SFAS No. 161, the table below outlines the location of our derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statement of operations.
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Table of ContentsFair Value of Derivative Financial Instruments
The Effect of Derivative Financial Instruments
Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from or cash disbursement to our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in “Gain (loss) on derivative financial instruments” on the condensed consolidated statement of operations, which do not impact cash flows, were losses of $173.2 million and $572.3 million for the three months ended June 30, 2009 and 2008, respectively, and were losses of $50.2 million and $916.5 million for the six months ended June 30, 2009 and 2008, respectively. Unrealized fair value adjustments included in “Interest expense” on the condensed consolidated statement of operations, which do not impact cash flows, were losses of $1.8 million and gains of $11.0 million for the three months ended June 30, 2009 and 2008, respectively, and were gains of $4.0 million and losses of $7.4 million for the six months ended June 30, 2009 and 2008, respectively. We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. As of June 30, 2009 and December 31, 2008, we had a net asset position of $350.2 million and $396.4 million, respectively. Fair value measurements We value our derivatives according to SFAS No. 157, “Fair Value Measurements,” or SFAS No. 157, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different than the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities. We prioritize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include: Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities. Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability. Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.
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Table of ContentsThe following presents a summary of the estimated fair value of our derivative financial instruments for the six months ended June 30, 2009 and the year ended December 31, 2008:
In accordance with FASB Interpretation 39 “Offsetting of Amounts Related to Certain Contracts—an interpretation of APB Opinion No. 10 and FASB Statement No. 105,” or FIN 39, we evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them gross on the condensed consolidated balance sheets. Net derivative asset values are determined, in part by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period. Oil and natural gas derivatives Our commodity price derivatives represent oil and natural gas swap and natural gas basis swap contracts. We have classified our oil and natural gas swaps and their related fair value tier as Level 2. Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate (WTI) oil prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above. Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub (HH) swap contracts coupled with basis swap contracts that convert the HH price index point to the Panhandle Eastern Pipe Line index (PEPL). The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps and PEPL index quotes for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.
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Table of ContentsThe following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of June 30, 2009:
At December 31, 2008, we had outstanding derivative contracts to mitigate price volatility covering 168,658 Mmcf of natural gas and 4,335 Mbbls of oil. At June 30, 2009, the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $71.93 and $75.35, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2009 and for 2010 were $4.39 and $6.06, respectively. Our derivative financial instruments used to mitigate price volatility covered 75.2% and 75.0% of our total equivalent Mcfe production for the three and six months ended June 30, 2009, respectively, and 80.3% and 79.5% of our total equivalent Mcfe production for the three and six months ended June 30, 2008, respectively. Interest rate swaps In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. The net derivative liability value attributable to our interest rate derivative contracts as of the end of the reporting period are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. We have classified our interest rate swaps and their related fair value tier as Level 2. During the three and six months ended June 30, 2009, we recognized increases of $4.6 million and $0.5 million, respectively, in interest expense related to our interest rate swaps. For the three and six months ended June 30, 2008, we recognized decreases of $11.4 million and $8.1 million, respectively, in interest expense related to our interest rate swaps. As of June 30, 2009 and December 31, 2008, the fair value of our interest rate swaps was a liability of $5.9 million and $9.9 million, respectively. Fair value of other financial instruments Effective April 1, 2009, we adopted FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” FSP No. FAS 107-1 and APB 28-1 requires disclosures about fair value of financial instruments in interim as well as in annual financial statements.
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Table of ContentsOur financial instruments include cash and equivalents, accounts receivable and payable, current portion of debt and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature. The estimated fair value of our 7 1/4% senior notes due January 15, 2011, or Senior Notes, is $429.2 million with a carrying amount of $450.5 million as of June 30, 2009. The estimated fair value has been calculated based on market quotes.
Our total debt is summarized as follows:
Credit agreements EXCO Resources Credit Agreement The EXCO Resources credit agreement, as amended, or the EXCO Resources Credit Agreement, has a borrowing base of $1.175 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At June 30, 2009, the one month LIBOR was 0.31%, which resulted in an interest rate of approximately 2.56% under the EXCO Resources Credit Agreement. At June 30, 2009, we had $1.046 billion of outstanding indebtedness and $125.3 million of available borrowing capacity under the EXCO Resources Credit Agreement. The borrowing base is redetermined semi-annually with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are on or about April 1 and October 1 of each year. On April 17, 2009, we entered into the fourth amendment to the EXCO Resources Credit Agreement, whereby the banking group reaffirmed the existing borrowing base commitments of $1.175 billion and increased our interest rate margins by 75 basis points, or bps. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. On July 29, 2009, the lenders agreed to certain hedging adjustments and acknowledgements of borrowing base within the EXCO Resources Credit Agreement in conjunction with the pending Mid-Continent Agreement wherein (i) the borrowing base will be $950.0 million upon closing of the Mid-Continent Agreement, (ii) the borrowing base will be $850.0 million upon closing of additional planned asset sales, assuming those transactions close, (iii) requirements to unwind a portion of derivatives within 10 days of certain dispositions will be waived and (iv) consents to the unwinding of derivatives, at EXCO’s option, were granted until the next regularly scheduled borrowing base redetermination on or about October 1, 2009. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more than 80% of its forecasted production from total proved reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012. As of June 30, 2009, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:
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The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement. EXCO Operating Credit Agreement The EXCO Operating credit agreement, as amended, or the EXCO Operating Credit Agreement, has a borrowing base of $1.3 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At June 30, 2009, the one month LIBOR was 0.31%, which resulted in an interest rate of approximately 2.81% under the EXCO Operating Credit Agreement. At June 30, 2009, we had $1.251 billion of outstanding indebtedness and $47.3 million of available borrowing capacity under the EXCO Operating Credit Agreement. The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. On April 17, 2009, we entered into the fourth amendment to the EXCO Operating Credit Agreement, whereby the banking group reaffirmed the existing borrowing base commitments of $1.3 billion and increased our interest rate margin by 75 bps. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending on borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. On July 29, 2009, the lenders agreed to consents to certain asset sales, hedge adjustments and acknowledgement of borrowing base under the EXCO Operating Credit Agreement. Among other things, the lenders (i) consented to contemplated pending transactions with BG Group for the upstream and midstream sales, including the contribution of our TGG and Talco entities to a newly formed unrestricted subsidiary, (ii) agreed the borrowing base will be $850.0 million following the sales to BG Group and the closing of the pending East Texas Agreement, (iii) agreed that requirements to unwind a portion of derivatives within 10 days upon closing of certain asset dispositions are waived and (iv) agreed that unwinding of derivatives, at EXCO’s option will be granted, until the next regularly scheduled borrowing base redetermination on or about October 1, 2009. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may enter into derivative financial instruments covering no more than 80% of the “forecasted production from total proved reserves” (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total proved reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012. As of June 30, 2009, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:
The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Operating Credit Agreement. Term Credit Agreement On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating may incur additional fees on unpaid principal amounts,
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Table of Contentsor duration fees, as defined in the agreement. These additional fees include a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on the unpaid outstanding balance on September 15, 2009. On June 15, 2009, we remitted the first duration fee payment of $15.0 million. The Term Credit Agreement is due and payable on January 15, 2010 and is guaranteed by all existing and future direct or indirect subsidiaries of EXCO Operating, including any guarantor of the EXCO Operating Credit Agreement. As of June 30, 2009, EXCO Operating was in compliance with the financial covenants contained in the Term Credit Agreement, which require during the period any amounts are outstanding under the Term Credit Agreement, that EXCO Operating:
At the borrower’s election, the Term Credit Agreement may bear interest at a rate per annum equal to (A) the ABR, defined as the highest of (i) the rate of interest publicly announced by JPMorgan as its prime rate in effect at its principal office in New York City, (ii) the federal funds effective rate from time to time plus 0.50%, and (iii) the Adjusted LIBO Rate (defined as the greater of (x) the rate at which Eurodollar deposits in the London interbank market for one month are quoted on Reuters BBA Libor Rates Page 3750, as adjusted for actual statutory reserve requirements for Eurocurrency liabilities, and (y) 4.0%) plus 1.0%, plus 5.0% or (B) the Adjusted LIBO Rate plus 6.0%. In all cases, the minimum interest rate on the Term Credit Agreement is 10.0%. At June 30, 2009, the interest rate on the $300.0 million outstanding on the Term Credit Agreement was 10.0%. The foregoing descriptions are not complete and are qualified in their entirety by the Term Credit Agreement. 7 1/4% senior notes due January 15, 2011 As of June 30, 2009 and December 31, 2008, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at June 30, 2009 and December 31, 2008 was $5.8 million and $7.6 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $429.2 million on June 30, 2009. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.
Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. As a result of these cumulative financial operating losses, we have provided valuation allowances of approximately $994.3 million until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.
We follow SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” or SFAS No. 131. Our reportable segments currently consist of exploration and production and midstream. Our exploration and production operational segment and midstream segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment is responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluate the performance of our operating segments based on segment profits, which includes segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses.
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Table of ContentsSummarized financial information concerning our reportable segments is shown in the following table:
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Table of ContentsThe following table reconciles the segment profits reported above to income (loss) before income taxes:
We evaluated our activity after June 30, 2009 until the date of issuance, August 6, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The Senior Notes are jointly and severally guaranteed by some of our subsidiaries (referred to collectively as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of EXCO Resources, or Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. EXCO Operating and its subsidiaries are designated as “Non-Guarantor Subsidiaries” in the accompanying condensed consolidating financial statements. There are no other Non-Guarantor Subsidiaries. The following financial information presents consolidating financial statements, which include:
Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the Guarantor Subsidiaries and Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited) June 30, 2009
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING BALANCE SHEET December 31, 2008
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the three months ended June 30, 2009
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the three months ended June 30, 2008
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the six months ended June 30, 2009
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the six months ended June 30, 2008
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the six months ended June 30, 2009
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Table of ContentsEXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the six months ended June 30, 2008
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Unless the context requires otherwise, references to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries. Forward-looking statements This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:
We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this quarterly report, including, but not limited to:
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We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2008. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas, the availability of capital from our revolving credit facilities and liquidity from capital markets. Declines in oil or natural gas prices may have a material adverse affect on our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Overview We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we have midstream operations in the East Texas/North Louisiana area. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries and together they are collectively referred to as EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt. This structure allows us to maintain two credit agreements: one at EXCO Resources, or the EXCO Resources Credit Agreement, which currently has a borrowing base of $1.175 billion and one at EXCO Operating, or the EXCO Operating Credit Agreement, which currently has a borrowing base of $1.3 billion. We expect to continue to grow by leveraging our management team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and exploitation projects, entering into beneficial joint development agreements, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. At times, we also look at strategic asset sales and joint development agreements to support our strategy of growth. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments, and manage our capital structure. Oil and natural gas prices have historically been volatile. On June 30, 2009, the spot market price for natural gas at Henry Hub was $3.89 per Mmbtu, a 70.3% decrease from June 30, 2008. The price of oil has also shown significant volatility, with a $69.79 per Bbl spot market price for oil at Cushing, Oklahoma at June 30, 2009, a 50.1% decrease from June 30, 2008. During the
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Table of Contentssix months ended June 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $46.34 per Bbl and $4.07 per Mcf, respectively, compared with the six months ended June 30, 2008 average realized prices of $109.21 per Bbl and $9.87 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity. Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions. At the end of the first quarter of 2009, we revised our expected capital expenditure estimate to approximately $500.0 million. We do not budget for acquisitions as these transactions are opportunistic in nature. In light of our drilling and completion results in our Haynesville shale area, we expect to increase our development drilling and leasing activities in East Texas/North Louisiana. Although our level of activity will increase, our expected capital expenditures will remain at approximately $500.0 million for 2009 as a result of the pending sale to an affiliate of BG Group, plc, or BG Group, as discussed below, which contains a provision in which BG Group will fund 75% of our capital expenditures on certain drilling and completion activities up to $400.0 million. While we are actively pursuing the sale of additional non-strategic assets, our future growth will depend upon our ability to continue to identify and add oil and natural gas reserves in excess of production at a reasonable cost. We plan to maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. In line with management’s goals for 2009, during the second quarter of 2009 we completed the sale of certain non-strategic assets, resulting in net cash proceeds of approximately $51.4 million after customary closing and post closing adjustments. We have an active, ongoing program to sell additional non-strategic assets and have reached agreements to close on certain asset sales in the third quarter of 2009 for total proceeds of approximately $390.0 million, subject to customary closing and post-closing adjustments. The largest dispositions we expect to close in the third quarter were announced in June. On June 28, 2009 we entered into two definitive agreements for the sale of our Norge Marchand Unit in Grady County, Oklahoma, other selected Oklahoma, Kansas and Texas Panhandle assets, or the Mid-Continent Agreement, and our Gladewater area and Overton Field assets in Gregg, Upshur and Smith Counties, Texas, or the East Texas Agreement, to Encore Operating, L.P., or Encore, totaling $375.0 million. The sales are expected to close in August 2009, subject to customary closing and post closing adjustments, and will be effective as of April 1, 2009. Net proceeds will be used to pay down our outstanding debt. On June 29, 2009 we entered into a definitive agreement with BG Group for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which includes most of our oil and natural gas assets in East Texas/North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), and for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We will receive $655.0 million in cash at closing, subject to customary closing and post-closing adjustments, pursuant to this transaction. BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, we will not be required to repay any of this funding. The joint development transaction is expected to close in August 2009 and will have an effective date of January 1, 2009. In addition, on August 5, 2009, we entered into a definitive agreement regarding the sale of 50% of our midstream assets within the AMI. Proceeds from the sale of the midstream assets will be $249.0 million subject to customary closing and post-closing adjustments. We expect to use the net proceeds from the transactions with BG Group to pay off our $300.0 million senior unsecured term credit agreement, or Term Credit Agreement, and use the remaining proceeds to pay down outstanding debt under our revolving credit agreements. In connection with the asset sales closed in the second quarter of 2009, we liquidated certain of our derivative contracts to stay in compliance with our debt agreements, resulting in gains of approximately $17.4 million. These gains are recorded in “Gain (loss) on derivative financial instruments” on our condensed consolidated statements of operations. We applied these receipts, along with a portion of the net receipts of the assets sales, to pay down outstanding debt under our revolving credit agreements. In connection with our divestiture transactions, we received cash deposits of $57.7 million, of which $37.5 million was deposited into an escrow account and is included in “Restricted cash” on the condensed consolidated balance sheets. These funds will be released upon the closing of the sales. Critical accounting policies We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill,
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Table of Contentsasset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008. Recent accounting pronouncements On June 29, 2009, the Financial Accounting Standards Board, or the FASB, issued FASB Statement No. 168, “FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a Replacement of FASB Statement No. 162,” or SFAS No. 168. SFAS No. 168 establishes “The FASB Accounting Standards Codification,” or Codification, which will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date of SFAS No. 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. SFAS No. 168 is effective for interim and annual periods ending after September 15, 2009. On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of June 30, 2009, we do not have any variable interest entities and as such, the final rule will not have an effect on our financial statements and disclosures. On June 12, 2009, the FASB issued FASB Statement No. 166, “Accounting for Transfers of Financial Assets,” or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements. On May 28, 2009, the FASB issued FASB Statement No. 165, “Subsequent Events,” or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009. On April 9, 2009, the FASB issued Staff Position 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,” or FSP FAS 157-4. FSP FAS 157-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph 19 of FASB SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” FSP FAS 157-4 is effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” to our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures. On April 9, 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 amend Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. The staff position also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” to our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures. On April 1, 2009, the FASB issued FASB Staff Position No. 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1. FSP 141(R)-1 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” or SFAS No. 141, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a
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Table of Contentsbusiness combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” in our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures. On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:
We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.
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Table of ContentsOur results of operations A summary of key financial data for the three and six months ended June 30, 2009 and 2008 related to our results of operations is presented below:
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