Range Resources - 10-Q quarterly report FY

 

 

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     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.

See accompanying notes.

     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. We have evaluated events or transactions through July 22, 2009 in conjunction with our preparation of these financial statements.

     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 (1) current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations and (2) the expansion of our unproved property positions in new shale plays. As economic conditions change and we continue to evaluate 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 six months of 2009 of $60.5 million compared to $5.6 million in the same period of the prior year. In the second quarter of 2009, we recorded abandonment and impairment expense of $41.0 million, which includes the expiration of certain significant Barnett Shale leases.

     In second quarter 2009, we identified certain leases amounting to $8.2 million that expired in 2006, 2007, and 2008, which were not expensed as required. Based on Staff Accounting Bulletin No. 108 (“SAB 108”), we have determined that these amounts are immaterial to each of the time periods affected and, therefore, we are not required to amend our previously filed reports. However, if these adjustments were recorded in 2009, we believe the impact could be material to this year. Therefore, we plan to adjust our previously reported results for 2006, 2007, and 2008 for these immaterial amounts as required by SAB 108. Such previous periods will be restated upon the next filing of our annual consolidated financial statements. In addition to recording additional lease expirations, we plan to make four other adjustments to prior year numbers to correct other immaterial items, which included the following adjustments: (1) tax expense of $3.5 million for discrete tax items recorded in 2008 related to 2007 (2) expense for volumetric ineffectiveness related to our derivative positions of $1.7 million recorded in 2008 related to 2007 (3) dry hole expense of $2.4 million not recorded in 2007 and (4) deferred compensation income of $7.1 million recorded in 2007 related to 2006 and prior years. The balance sheet as of December 31, 2008 has been adjusted to reflect the cumulative impact of such errors. As a result, oil and gas properties decreased by $10.7 million, deferred tax liability decreased $4.2 million and retained earnings decreased by $6.5 million. For additional information, see Footnote 18.

     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 dividend 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 SFAS No. 141(R) did not have an effect on our reported financial position or earnings.

     In April 2009, two related FASB Staff Positions were issued:

     FSP FAS 107-1 amends SFAS No. 107 and Accounting Principles Board (“APB”) Opinion No. 28 to require disclosures about fair value of financial instruments in interim reporting periods for publicly traded companies. FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability has significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. Additional disclosures are also required. We adopted the provisions of the FSP’s for the period ending June 30, 2009. The adoption of these FSP’s did not have an impact on our financial position or results of operations.

     In May 2009, the FASB issued SFAS No. 165, “Subsequent Events.” SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted SFAS No. 165 for the period ending June 30, 2009, which did not have an impact on our financial position or results of operations.

     In second quarter 2009, we sold certain oil properties in West Texas for proceeds of $182.0 million. The proceeds from the sale of these oil properties were credited to oil and gas properties, with no gain or loss recognized, as the disposition did not materially impact the depletion rate of the remaining properties in the amortization base. In first quarter 2008, we sold East Texas properties for proceeds of $64.4 million and recorded a gain of $20.2 million.

     Income tax expense (benefit) 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 (loss), 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 June 30, 2009 and 2008, our overall effective tax rate on pre-tax income from operations was different than the statutory rate of 35% due primarily to state

income taxes. For the six months ended June 30, 2009, our overall effective tax rate on income from operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowance and permanent differences. For the six months June 30, 2008, our overall effective tax rate on income from operations was different than the statutory rate due primarily to state income taxes. 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 $160.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $92.5 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2008 was $10.7 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 (loss) 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 (loss) per common share (in thousands except per share amounts):

     The weighted average common shares — basic amount excludes 2.4 million shares at June 30, 2009 and 2.2 million shares at June 30, 2008, of restricted stock that is held in our deferred compensation plan (although all restricted stock is issued and outstanding upon grant). Due to our net loss from operations for the three months and the six months ended June 30, 2009, we excluded all 10.4 million outstanding stock options/SARs and restricted stock because the effect would have been anti-dilutive. Due to our net loss from operations for the three months and the six months ended June 30, 2008, we excluded all 10.0 million outstanding stock options/SARs and restricted stock because the effect would have been anti-dilutive.

     The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2009 and the year ended December 31, 2008 (in thousands):

     The $66.8 million of capitalized exploratory well costs at June 30, 2009 was incurred in 2009 ($18.5 million), in 2008 ($42.4 million) and in 2007 ($5.9 million). Of the eight projects that have exploratory costs capitalized for more than one year, seven projects are Marcellus Shale wells.

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at June 30, 2009 is shown parenthetically). No interest expense was capitalized during the three months or the six months ended June 30, 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 June 30, 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 2.4% 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 June 30, 2009, the outstanding balance under the bank credit facility was $403.0 million and there was $847.0 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 2.5% for the three months ended June 30, 2009 compared to 4.8% for the three months ended June 30, 2008. The weighted average interest rate on the bank credit facility was 2.6% for the six months ended June 30, 2009 compared to 4.9% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At June 30, 2009, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans. At July 20, 2009, the interest rate (including applicable margin) was 2.3%.

     In May 2009, we issued $300.0 million aggregate principal amount of 8.0% senior subordinated notes due 2019 (“8.0% Notes”). The 8.0% Notes were issued at a discount, which is being amortized over the life of the 8.0% Notes due 2019. Interest on the 8.0% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 8.0% Notes, in whole or in part, at any time on or after May 15, 2014, at redemption prices of 104.0% of the principal amount as of May 15, 2014 and declining to 100.0% on May 15, 2017 and thereafter.

Before May 15, 2012, we may redeem up to 35% of the original aggregate principal amount of the 8.0% Notes at a redemption price equal to 108.0% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 8.0% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.

     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 June 30, 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 June 30, 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 six months ended June 30, 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 June 30, 2009, we had open swap contracts covering 17.0 Bcf of gas at prices averaging $7.40 per mcf. We also had collars covering 61.3 Bcf of gas at weighted average floor and cap prices of $6.64 to $7.85 per mcf and 1.5 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 June 30, 2009, was a net unrealized pre-tax gain of $169.4 million. These contracts expire monthly through December 2010.

     The following table sets forth our derivative volumes and average hedge prices as of June 30, 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. Our AOCI at June 30, 2009 and December 31, 2008 relate solely to our derivative activities. 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 June 30, 2009, an unrealized pre-tax derivative gain of $87.1 million was recorded in AOCI. This gain is expected to be reclassified into earnings in 2009 ($84.5 million) and 2010 ($2.6 million). 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 includes $53.2 million of gains in the three months ended June 30, 2009 compared to losses of $50.0 million in the three months ended June 30, 2008 related to settled hedging transactions. For the six months ended June 30, 2009, oil and gas sales include $104.5 million of gains compared to losses of $44.8 million in the same period of the prior period related to settled hedging transactions. Any ineffectiveness associated with these hedges is reflected in the statement of operations 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 June 30, 2009 includes ineffective unrealized gains of $356,000 compared to unrealized gains of $558,000 in the same period of 2008. The six months ended June 30, 2009 includes ineffective unrealized losses of $97,000 compared to unrealized losses of $2.7 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 sales 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 six months of 2009, there were gains of $5.4 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives. In July 2009, we liquidated four oil commodity contracts and received proceeds of $119,000.

     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 loss of $4.5 million at June 30, 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 and the six months ended June 30, 2009 and 2008 (in thousands):

     The combined fair value of derivatives included in our consolidated balance sheets as of June 30, 2009 and December 31, 2008 is summarized below (in thousands). We conduct derivative activities with thirteen financial institutions, eleven 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 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 June 30, 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. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, 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 June 30, 2009, interest and dividends were $50,000 and mark-to-market was a gain of $4.9 million. For the three months ended June 30, 2008, interest and dividends were $79,000 and the mark-to-market was a loss of $666,000. For the six months ended June 30, 2009, interest and dividends were $93,000 and mark-to-market was a gain of $3.4 million. For the six months ended June 30, 2008, interest and dividends were $266,000 and the mark-to-market was a loss of $5.3 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 $753,000 at June 30, 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 thirteen financial institutions, eleven 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 June 30, 2009, our net derivative asset includes a payable to J. Aron & Company of $33,000 and a receivable from Mitsui & Co. for $9.9 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 non-employee, 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 June 30, 2009:

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2009 was $15.39. 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 1.5%; dividend yield of 0.4%; expected volatility of 59%; and an expected life of 3.5 years.

     As of June 30, 2009, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $115.0 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $102.2 million and 1.9 years. As of June 30, 2009, the number of fully vested awards and awards expected to vest was 7.8 million. The weighted average exercise price and weighted average remaining contractual life of these awards was $29.80 and 2.7 years and the aggregate intrinsic value was $114.3 million. As of June 30, 2009, unrecognized compensation cost related to the awards was $37.1 million, which is expected to be recognized over a weighted average period of 1.4 years. Of the 8.0 million stock option/SARs outstanding at June 30, 2009, 1.8 million are stock options and 6.2 million are SARs.

     During the first six months of 2009, 532,900 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $37.70 with a three-year vesting period and 22,700 shares were granted to our directors at an average price of $41.60 with immediate vesting. In the first six months of 2008, we issued 312,500 shares of restricted stock as compensation to employees at an average price of $65.84 with a three-year vesting period and 10,800 shares were granted to our directors at a price of $75.00 with immediate vesting. 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 $8.8 million in the first six months of 2009 compared to $7.4 million in the six-month period ended June 30, 2008. As of June 30, 2009, unrecognized compensation cost related to restricted stock awards was $30.0 million, which is expected to be recognized over the weighted average period of 1.5 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 June 30, 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 grantor 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 liability associated with 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 $13.2 million in the first six months of 2009 compared to mark-to-market expense of $28.1 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 June 30, 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.

     As further explained in Footnote 2, we plan to adjust previously reported results for 2006, 2007 and 2008 for immaterial errors as required by SAB 108. Additionally, we have restated the second quarter and the six months ended June 30, 2008 to reflect the impact of such errors. The following presents these adjustments in detail: