Range Resources - 10-Q quarterly report FY

 

 

(Mark one)

(Exact name of registrant as specified in its charter)

     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.

     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 during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).

      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).

 

 

     Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

     We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range Resources Corporation is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2008 Annual Report on Form 10-K filed on February 25, 2009. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements. Certain reclassifications of prior year data have been made to conform to 2009 classifications.

     We adhere to Statement of Financial Accounting Standards (“SFAS”) No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing impairment of capitalized costs related to unproved properties. These costs are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider time, geologic and engineering factors to evaluate the need for impairment of these costs. We continue to experience an increase in lease expirations and impairment expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations, and our rapid expansion of our unproved property positions in new shale plays. As economic conditions change and we continue to prove up unproved properties, our estimates of expirations likely will change and we may increase or decrease impairment expense. We recorded abandonment and impairment expense in the first quarter of 2009 of $19.6 million versus $1.4 million in the same period of the prior year.

     In February 2008, the Financial Accounting Standards Board (“FASB”) issued staff position (“FSP”) SFAS No. 157-2 which delayed the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral of SFAS No. 157 primarily applied to our asset retirement obligation (“ARO”), which uses fair value measures at the date incurred to determine our liability and any property impairments that may occur. We adopted FSP SFAS No. 157-2 effective January 1, 2009 and the adoption did not have a material effect on our consolidated results of operations.

     In June 2008, the FASB issued Staff Position No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities,” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividends equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. We adopted FSP EITF 03-6-1 on January 1, 2009 with no impact on our reported earnings per share.

     In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” 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 any 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. We adopted SFAS No. 161 on January 1, 2009. See Note 11 for additional disclosures required by SFAS No. 161.

     In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase method of accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process

research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. The adoption of adopting SFAS No. 141(R) did not have an effect on our reported financial position or earnings.

     In first quarter 2008, we sold East Texas properties for proceeds of $64.4 million and recorded a gain of $20.7 million. We are currently considering the possible sale of certain oil properties in West Texas as well as properties in other areas.

     Income tax included in continuing operations was as follows (in thousands):

     We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended March 31, 2009, our overall effective tax rate on income from operations was different than the statutory rate of 35% due primarily to state income taxes. For the three months ended March 31, 2008, our overall effective tax rate on income from operations was different than the statutory rate of 35% primarily due to state income taxes, a decrease in our deferred tax asset related to state tax carryforwards ($1.5 million) and a valuation allowance against a deferred tax asset related to our deferred compensation plan ($2.3 million). We expect our effective tax rate to be approximately 37% for the remainder of 2009.

     At December 31, 2008, we had regular tax net operating loss (“NOL”) carryforwards of $158.7 million and alternative minimum tax (“AMT”) NOL carryforwards of $90.8 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2008 was $10.2 million, net of the SFAS No. 123(R) deduction for unrealized benefits. At December 31, 2008, we have AMT credit carryforwards of $1.8 million that are not subject to limitation or expiration.

     Basic income per share is based on weighted average number of common shares outstanding. Diluted income per share includes exercise of stock options, stock appreciation rights and restricted shares, provided the effect is not anti-dilutive. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

     The weighted average common shares – basic amount excludes 2.3 million shares at March 31, 2009 and 2.1 million shares at March 31, 2008, of restricted stock that is held in our deferred compensation plan (although all restricted stock is issued and outstanding upon grant). Stock appreciation rights, or SARs, for 1.7 million shares for the three months ended March 31, 2009 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. SARs for 500 shares for the three months ended March 31, 2008 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

     The following table reflects the changes in capitalized exploratory well costs for the three months ended March 31, 2009 and the year ended December 31, 2008 (in thousands):

     The $57.8 million of capitalized exploratory well costs at March 31, 2009 was incurred in 2009 ($6.9 million), in 2008 ($45.0 million) and in 2007 ($5.9 million).

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at March 31, 2009 is shown parenthetically). No interest expense was capitalized during the three months ended March 31, 2009 and 2008.

     In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On March 31, 2009, the borrowing base was $1.5 billion and our facility amount was $1.25 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-six commercial banks each holding between 2.3% and 5.0% of the total facility. Of those twenty-six banks, thirteen are domestic banks and thirteen are foreign banks or wholly owned subsidiaries of foreign banks. The facility amount may be increased up to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility amount increase. At March 31, 2009, the outstanding balance under the bank credit facility was $807.0 million and there was $443.0 million of borrowing capacity available under the facility amount. The loan matures October 25, 2012. Borrowing under the bank credit facility can either be the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the adjusted LIBO Rate (as defined) plus a spread ranging from 1.75% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 2.6% for the three months ended March 31, 2009 compared to 5.0% for the three months ended March 31, 2008. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At March 31, 2009, the commitment fee was 0.375% and the interest rate margin was 2.0% on our LIBOR loans. At April 24, 2009, the interest rate (including applicable margin) was 2.7%.

     Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at March 31, 2009.

     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At March 31, 2009, we were in compliance with these covenants.

     Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. A reconciliation of our liability for plugging, abandonment and remediation costs for the three months ended March 31, 2009 is as follows (in thousands):

     Accretion expense is recognized as a component of depreciation, depletion and amortization on our statement of operations.

     We have authorized capital stock of 485 million shares, which includes 475 million shares of common stock and 10 million shares of preferred stock. The following is a summary of changes in the number of common shares outstanding since the beginning of 2008:

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. We have $6.8 million remaining under this authorization.

     We use commodity–based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. These contracts consist of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At March 31, 2009, we had open swap contracts covering 24.6 Bcf of gas at prices averaging $7.47 per mcf. We also had collars covering 54.5 Bcf of gas at weighted average floor and cap prices of $7.39 to $8.01 per mcf and 2.2 million barrels of oil at weighted average floor and cap prices of $64.01 to $76.00 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price, generally New York Mercantile Exchange (“NYMEX”), on March 31, 2009, was a net unrealized pre-tax gain of $274.6 million. These contracts expire monthly through December 2009.

     The following table sets forth our derivative volumes as of March 31, 2009:

     Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of “Accumulated other comprehensive income (loss),” (“AOCI”) which is later transferred to earnings when the underlying physical transaction occurs. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized in earnings. As of March 31, 2009, an unrealized pre-tax derivative gain of $145.0 million was recorded in AOCI. This gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on market prices at the contract settlement date.

     For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to oil and gas sales in the period the hedged production is sold. Oil and gas sales include $51.3 million of gains in the three months ended March 31, 2009 compared to gains of $5.2 million in the three months ended March 31, 2008. Any ineffectiveness associated with these hedges is reflected in the income statement caption called “Derivative fair value income (loss).” The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. The three months ended March 31, 2009 includes ineffective unrealized losses of $453,000 compared to unrealized losses of $3.2 million in the same period of 2008.

     To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas revenue when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as a “Derivative fair value income or loss.” During the first quarter of 2009, there were gains of $2.3 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives.

     Some of our derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in the income statement caption called “Derivative fair value income (loss)” (see table below).

     In addition to the swaps and collars discussed above, we have entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix a portion of our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $5.8 million at March 31, 2009 and these swaps expire through 2011.

     The following table presents information about the components of derivative fair value income (loss) in the three months ended March 31, 2009 and 2008 (in thousands):

     The combined fair value of derivatives included in our consolidated balance sheets as of March 31, 2009 and December 31, 2008 is summarized below (in thousands). We conduct derivative activities with twelve financial institutions, ten of which are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.

     We adopted SFAS No. 161 at the beginning of the first quarter of 2009 and the expanded disclosures required by SFAS No. 161 are presented below. The table below provides data about the carrying values of derivatives that qualify for hedge accounting and derivatives that do not qualify for hedge accounting (in thousands):

     The table below provides data about the amount of gains and losses related to cash flow derivatives that qualify for hedge accounting included in the balance sheet caption “Accumulated other comprehensive income” (AOCI) and in our statement of operations (in thousands):

     We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

     These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange – traded and measured at fair value with a market approach using March 31, 2009 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes.

     Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in the balance sheet category called “other assets.” We adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” on January 1, 2008 which resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our trading securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. Interest and dividends and mark-to-market gains/losses are included in the statement of operations category called “Deferred compensation plan expense.” For the three months ended March 31, 2009, interest and dividends were $43,000 and mark-to-market was a loss of $1.1 million. For the three months ended March 31, 2008, interest and dividends were $187,000 and the mark-to-market was a loss of $4.6 million.

     Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as necessary to limit risk of loss. Our allowance for uncollectible receivables was $783,000 at March 31, 2009 and $954,000 at December 31, 2008. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. These contracts consist of collars and fixed price swaps. This exposure is diversified among major investment grade financial institutions and we have master netting agreements with the counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include twelve financial institutions, ten of which are secured lenders in our bank credit facility. Mitsui & Co. and J. Aron & Company are the two counterparties not in our bank group. At March 31, 2009, our net derivative asset includes a receivable from J. Aron & Company of $517,000 and a receivable from Mitsui & Co. for $19.8 million. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

     We have six equity-based stock plans, of which two are active. Under the active plans, incentive and nonqualified options, SARs and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of outside, independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. Since the middle of 2005, only SARs have been granted under the plans to limit the dilutive impact of our equity plans. Information with respect to stock option and SARs activities is summarized below:

     The following table shows information with respect to outstanding stock options and SARs at March 31, 2009:

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2009 was $14.83. The fair value of each stock option/SAR granted during 2009 was estimated as of the date of grant using the Black-Scholes-Merton option-pricing model based on the following average assumptions: risk-free interest rate of 1.4%; dividend yield of 0.5%; expected volatility of 61%; and an expected life of 3.5 years.

     As of March 31, 2009, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $117.9 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $103.3 million and 2.0 years. As of March 31, 2009, the number of fully vested awards and awards expected to vest was 7.4 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $28.65 and 2.8 years and the aggregate intrinsic value was $117.1 million. As of March 31, 2009, unrecognized compensation cost related to the awards was $33.8 million, which is expected to be recognized over a weighted average period of 1.4 years. Of the 7.6 million stock option/SARs outstanding at March 31, 2009, 1.8 million are stock options and 5.8 million are SARs.

     During the first three months of 2009, 282,300 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $34.24 with a three-year vesting period. In the first three months of 2008, we issued 176,400 shares of restricted stock as compensation to employees at an average price of $58.60 with a three-year vesting period. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $3.9 million in the first three months of 2009 compared to $3.3 million in the three-month period ended March 31, 2008. As of March 31, 2009, unrecognized compensation cost related to restricted stock awards was $24.3 million, which is expected to be recognized over the next 3 years (excluding mark-to-market that would also be recognized over that same time period). All of our restricted stock grants are held in our deferred compensation plans (see discussion below). All awards granted have been issued at prevailing market prices at the time of the grant and the vesting of these shares is based upon an employee’s continued employment with us.

     A summary of the status of our non-vested restricted stock outstanding at March 31, 2009 is presented below:

     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (“2005 Deferred Compensation Plan”). The 2005 Deferred Compensation Plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest such amounts in Range common stock or make other investments at the individual’s discretion. The assets of the plan are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The vested portion of the stock held in the Rabbi Trust is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value in other assets on our consolidated balance sheet. Changes in the market value of the securities are charged or credited to deferred compensation plan expense each quarter. The deferred compensation liability on our balance sheet reflects the vested market value of the marketable securities and stock held in the Rabbi Trust. We recorded non-cash, mark-to-market expense related to our deferred compensation plan of $12.4 million in the first quarter 2009 compared to mark-to-market expense of $20.6 million in the same period of 2008.

     We have entered firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of March 31, 2009, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):

     We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

     In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

               We will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

     The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2008 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A. Risk Factors, in our 2008 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate only to our continuing operations.

     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. These policies and estimates are described in the 2008 Form 10-K except as updated below. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: accounting for oil and gas revenue, oil and gas properties, stock-based compensation, derivative financial instruments, asset retirement obligations and deferred taxes.

     We adhere to SFAS No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing impairment of capitalized costs related to unproved properties. These costs are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider time, geologic and engineering factors to evaluate the need for impairment of these costs. We continue to experience an increase in lease expirations and impairment expense caused by current economic conditions, which have impacted our future drilling plans thereby increasing the amount of expected lease expirations, and our rapid expansion of our unproved property positions in new shale plays. As economic conditions change and we continue to prove up unproved properties, our estimates of expirations likely will change and we may increase or decrease impairment expense.

     Total revenues increased $71.1 million, or 35% for first quarter 2009 over the same period of 2008. The increase includes a $199.3 million increase in derivative fair value income offset by a $104.2 million, or 34% decrease in oil and gas sales. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. For first quarter 2009, production increased 12% from the same period of the prior year with the continued success of our drilling program. Realized prices were 31% lower in first quarter 2009 when compared to first quarter 2008. We believe oil and gas prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new regulations and the level of oil and gas production in North America and worldwide.

     As a result of the significant drop in commodity prices, we continue to implement initiatives to reduce capital spending and operating costs. This plan includes reduced drilling activities until margins improve as a result of (i) increased commodity prices (ii) reduced gas price differentials relative to NYMEX quoted prices in the areas where we produce and/or (iii) decreased well costs. In the first quarter of 2009, we experienced some cost savings caused by lower commodity prices but operating costs have not decreased at the same rate as commodity prices. Therefore on average, most of our expenses increased on both an absolute and per mcfe basis. Our operating teams continue to implement initiatives to reduce controllable production costs. We expect to see further cost reductions in 2009, as we expect lower spending levels in the industry will reduce demand for goods and services and eventually lower costs, but we are uncertain how quickly costs will decline and by how much. However, as we continue to expand our Marcellus Shale team to meet the needs of this developing asset, we expect to see upward pressure on our general and administrative costs per mcfe.

     Our oil and gas sales vary from quarter to quarter as a result of changes in realized commodity prices and volumes of production sold. Hedges included in oil and gas sales reflect settlement on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in the income statement caption called “Derivative fair value income (loss).” The following table summarizes the primary components of oil and gas sales for the three months ended March 31, 2009 and 2008 (in thousands):

     Our production continues to grow through continued drilling success as we place new wells into production. For first quarter 2009, our production volumes increased, from the same period of the prior year, 14% in our Appalachian Area, 11% in our Gulf Coast Area and 9% in our Southwestern Area. Our production for the three months ended March 31, 2009 and 2008 is shown below:

     Our average realized price (including all derivative settlements) received for oil and gas was $6.62 per mcfe in first quarter 2009 compared to $9.55 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlement for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months ended March 31, 2009 and 2008 are shown below:

     Derivative fair value income (loss) includes income of $75.5 million in first quarter 2009 compared to a loss of $123.8 million in the same period of 2008. Some of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. All unrealized and realized gains and losses related to these contracts are included in the income statement caption “Derivative fair value income (loss).” We have also entered into basis swap agreements, which do not qualify for hedge accounting and are also marked to market. Not using hedge accounting treatment creates volatility in our revenues as unrealized gains and losses from non-hedge derivatives are included in total revenues and are not included in our balance sheet caption “Accumulated other comprehensive income (loss).” Due to falling commodity prices in first quarter 2009 for oil and natural gas, we reported a non-cash unrealized mark-to-market gain from our oil and gas derivatives of $31.5 million. If commodity prices for oil and natural gas continue to fall, we would expect to incur additional realized and non-cash unrealized gains from our oil and gas hedges. If this occurs, our results of operations, net income and earnings per share may be affected. Hedge ineffectiveness, also included in this income statement category, is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133.

     The following table presents information about the components of derivative fair value income (loss) for the three months ended March 31, 2009 and 2008 (in thousands):

     Other revenue for first quarter 2009 decreased to a loss of $1.8 million from a gain of $20.6 million in the same period of 2008. First quarter 2009 includes a loss from equity investments of $919,000. First quarter 2008 includes a gain of $20.7 million from the sale of certain East Texas properties and a loss from equity method investments of $275,000.

     Our costs, on an absolute basis, have increased as we continue to grow. We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about these expenses on an mcfe basis for the three months ended March 31, 2009 and 2008:

     Direct operating expense increased $2.6 million in first quarter 2009 to $35.5 million due to higher volumes. Our operating expenses are increasing as we add new wells from development and maintain production from our existing properties. We incurred $1.7 million ($0.05 per mcfe) of workover costs in first quarter 2009 versus $1.9 million ($0.06 per mcfe) in 2008. On a per mcfe basis, direct operating expenses for first quarter 2009 decreased $0.03 or 3% from the same period of 2008 with the decrease consisting primarily of lower workover costs ($0.01 per mcfe), lower utility costs along with lower overall industry costs. The following table summarizes direct operating expenses per mcfe for the three months ended March 31, 2009 and 2008:

     Production and ad valorem taxes are paid based on market prices and not hedged prices. For the first quarter, these taxes decreased $5.6 million or 40% from the same period of the prior year due to the significant decline in pre-hedge prices. On a per mcfe basis, production and ad valorem taxes decreased to $0.22 in first quarter 2009 from $0.41 in the same period of 2008 primarily due to a 55% decrease in pre-hedge prices.

     General and administrative expense for first quarter 2009 increased $7.5 million from the first quarter of the prior year due primarily to higher salaries and benefits ($4.2 million) due to our continued expansion of our Marcellus Shale team, higher stock-based compensation ($1.5 million) and higher office expenses, including rent and information technology. The stock-based compensation represents amortization of restricted stock grants and expense related to SAR grants. The following table summarizes general and administrative expenses per mcfe for first quarter of 2009 and 2008:

     Interest expense for first quarter 2009 increased $3.5 million to $26.6 million due to the refinancing of certain debt from floating to higher fixed rates in second quarter 2008 combined with higher overall debt balances. In May 2008, we issued $250.0 million of 7.25% Notes due 2018, which added $4.5 million of interest costs in first quarter 2009. The proceeds from the issuance were used to retire lower interest bank debt, to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for first quarter 2009 was $787.2 million compared to $539.8 million for first quarter 2008 and the weighted average interest rates were 2.6% in first quarter 2009 compared to 5.0% in first quarter 2008.

     Depletion, depreciation and amortization (“DD&A”) increased $14.2 million, or 20%, to $84.3 million in first quarter 2009 with a 12% increase in production and a 7% increase in depletion rates. On a per mcfe basis, DD&A increased from $2.08 in first quarter 2008 to $2.25 in first quarter 2009. The increase in DD&A per mcfe is related to increasing drilling costs, higher acquisition costs and the mix of our production. The following table summarizes DD&A expenses per mcfe for the three months ended March 31, 2009 and 2008:

     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In the three months ended March 31, 2008 and 2009, stock-based compensation represents the amortization of restricted stock grants and expenses related to SAR grants. In first quarter 2009, stock-based compensation is a component of direct operating expense ($730,000), exploration expense ($1.1 million) and general and administrative expense ($6.2 million) for a total of $8.3 million. In first quarter 2008, stock-based compensation was a component of direct operating expense ($578,000), exploration expense ($1.1 million) and general and administrative expense ($4.6 million) for a total of $6.4 million.

     Exploration expense decreased $3.3 million in first quarter 2009 primarily due to lower dry hole costs. The following table details our exploration-related expenses for the three months ended March 31, 2009 and 2008 (in thousands):

     Abandonment and impairment of unproved properties expense was $19.6 million in first quarter 2009 compared to $1.4 million in the same period of the prior year. We continue to experience increases in lease expirations and impairment expenses caused by current economic conditions which have impacted our future drilling plans and our rapid expansion of our unproved property positions in new shale plays.

     Deferred compensation plan expense was $12.4 million compared to $20.6 million in the same period of the prior year. Our stock price increased from $34.39 at December 31, 2008 to $41.16 at March 31, 2009. During the same period in the prior year, our stock price increased from $51.36 at December 31, 2007 to $63.45 at March 31, 2008. This non-cash expense relates to the increase or decrease in value of our common stock that is vested and held in the deferred compensation plan. Our deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.

     Income tax expense for the first quarter 2009 increased to $18.8 million, reflecting a 458% increase in income from operations before taxes compared to the same period of 2008. First quarter 2009 provided for tax expense at an effective rate of 36.6% compared to tax expense at an effective rate of 81.1% in the same period of 2008. First quarter 2008 included $3.8 million of additional tax expense for discrete items. We expect our effective tax rate to be approximately 37% for the remainder of 2009.

     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with both uncommitted and committed availability, asset sales and access to both the debt and equity capital markets. During the last six months, we have taken several steps to improve our liquidity as a result of the deterioration in the capital markets and the decrease in oil and gas commodity prices. In December 2008, we elected to utilize the expansion option under our bank credit facility and increased our credit facility commitment by $250.0 million which made the current bank commitment $1.25 billion. In March 2009, we completed our semi-annual borrowing base redetermination with our bank group reaffirming our $1.5 million borrowing base. We have announced a $700.0 million 2009 capital budget, which reflects reduced spending all areas except the Marcellus Shale play. We are currently considering the possible sale of certain oil properties in West Texas as well as properties in other areas.

     During the three months ended March 31, 2009, our cash provided from continuing operations was $149.2 million and we spent $169.8 million on capital expenditures and $84.4 million of acreage purchases. During this period, financing activities provided net cash of $100.9 million. At March 31, 2009, we had $756,000 in cash, total assets of $5.7 billion and a debt-to-capitalization ratio of 43.2%. Long-term debt at March 31, 2009 totaled $1.9 billion including $807.0 million of bank credit facility debt and $1.1 billion of senior subordinated notes. Available committed borrowing capacity under the bank credit facility at March 31, 2009 was $443.0 million.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities and unused committed borrowing capacity under the bank credit facility will be adequate to satisfy near-term financial obligations and liquidity needs. However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. Sustained lower oil and gas prices or a reduction in production and reserves would reduce

our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We currently have not entered into any hedging agreements for 2010 and beyond except for a limited amount of basis swaps. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices, which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies.

     On March 31, 2009, the bank credit facility had a $1.5 billion borrowing base and a $1.25 billion facility amount. The borrowing base represents an amount approved by the bank group that can be borrowed based on our assets, while our $1.25 billion facility amount is the amount the banks have committed to fund pursuant to the credit agreement. Remaining credit availability is $368.0 million on April 24, 2009. Our bank group is comprised of twenty-six commercial banks, with no one bank holding more than 5.0% of the bank credit facility. We believe our large number of banks and relatively low hold levels allow for significant lending capacity should we elect to increase our $1.25 billion commitment up to the $1.5 billion borrowing base and also allow for flexibility should there be additional consolidation within the banking sector.

     Our bank credit facility and our indentures governing our senior subordinated notes all contain covenants that, among other things, limit our ability to pay dividends and incur additional indebtedness. We were in compliance with these covenants at March 31, 2009. Please see Note 8 to our consolidated financial statements for additional information.

     Cash flows from operations primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We sell substantially all of our oil and gas production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by higher prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowing under the credit facility. As of March 31, 2009, we have entered into hedging agreements covering 92.3 Bcfe for 2009.

     Net cash provided from continuing operations for the three months ended March 31, 2009 was $149.2 million compared to $206.3 million in the three months ended March 31, 2008. Cash flow from operations was lower than the prior year with higher production from development activity and acquisitions more than offset by lower prices. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in the consolidated statement of cash flows) in the three months ended March 31, 2009 was a positive $1.7 million compared to a negative $24.7 million in the same period of the prior year.

     Net cash used in investing for the three months ended March 31, 2009 was $250.1 million compared to $485.2 million in the same period of 2008. The 2009 period included $159.2 million of additions to oil and gas properties and $84.4 million of acreage purchases. Acquisitions for the first three months of 2009 include the purchase of certain Marcellus Shale leasehold acreage for $56.7 million. The 2008 period included $207.1 million of additions to oil and gas properties and $333.4 million of acquisitions and other investments, offset by proceeds of $63.3 million from asset sales.

     Net cash provided from financing for the three months ended March 31, 2009 was $100.9 million compared to $275.0 million in the first three months of 2008. This decrease was primarily due to the lower borrowings on our bank credit facility. During the first three months of 2009, total debt increased $114.1 million.

     On March 3, 2009, the Board of Directors declared a dividend of four cents per share ($6.3 million) on our common stock, which was paid on March 31, 2009 to stockholders of record at the close of business on March 17, 2009.

     The 2009 capital budget is currently set at $700.0 million (excluding proved property acquisitions) and based on current projections, is expected to be funded with internal cash flow. We may, from time to time during 2009, make borrowings under our credit facility but expect that for all of 2009 to require no significant incremental borrowings from ending 2008 levels. Acreage purchases during the year include $56.7 million of purchases in the Marcellus Shale and $6.4 million in the Barnett Shale which were funded with borrowings under the credit facility. For the three months ended March 31, 2009, $178.9 million of development and exploration spending was funded with internal cash flow and borrowings under our bank credit facility. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestiture and continued growth. We may sell assets, issue subordinated notes or other debt securities, or issue additional shares of stock to fund capital expenditures or acquisitions, extend maturities or repay debt.

     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation commitments and other liabilities. Since December 31, 2008, the material changes to our contractual obligations included a $114.1 million increase in long-term debt and an increase in our transportation commitments (see table and discussion below).

     We have entered into firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. As of March 31, 2009, future minimum transportation fees under our gas transportation commitments were as follows (in thousands):

     We are involved in various legal actions and claims arising in the ordinary course of business. We believe the resolution of these proceedings will not have a material adverse effect on our liquidity or consolidated financial position.

     We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. These contracts consist of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At March 31, 2009, we had open swaps contracts covering 24.6 Bcf of gas at prices averaging $7.47 per mcf. We also have collars covering 54.5 Bcf of gas at weighted average floor and cap prices of $7.39 and $8.01 per mcf and 2.2 million barrels of oil at weighted average floor and cap prices of $64.01 and $76.00 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of contract prices and a reference price, generally NYMEX, on March 31, 2009 was a net unrealized pre-tax gain of $274.6 million. The contracts expire monthly through December 2009. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or decreases in oil and gas sales in the period the hedged production is sold. In the first three months of 2009, oil and gas sales included realized hedging gains of $51.3 million compared to gains of $5.2 million in the same period of 2008.

     At March 31, 2009, the following commodity derivative contracts were outstanding: