e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark one)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2008
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 001-12209
RANGE RESOURCES CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware   34-1312571
(State or Other Jurisdiction of Incorporation or Organization)   (IRS Employer Identification No.)
     
100 Throckmorton Street, Suite 1200, Fort Worth, Texas   76102
(Address of Principal Executive Offices)   (Zip Code)
(817) 870-2601
(Registrant’s Telephone Number, Including Area Code)
Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ       No o
     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):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o       No þ
155,335,630 Common Shares were outstanding on October 21, 2008.
 
 

 


RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended September 30, 2008
     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.
TABLE OF CONTENTS
         
        Page
PART I — FINANCIAL INFORMATION    
 
  Financial Statements:    
 
 
  Consolidated Balance Sheets (unaudited)   3
 
 
  Consolidated Statements of Operations (unaudited)   4
 
 
  Consolidated Statements of Cash Flows (unaudited)   5
 
 
  Consolidated Statements of Comprehensive Income (unaudited)   6
 
 
  Selected Notes to Consolidated Financial Statements (unaudited)   7
 
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   21
 
  Quantitative and Qualitative Disclosures about Market Risk   32
 
  Controls and Procedures   33
 
PART II — OTHER INFORMATION    
 
  Unregistered Sales of Equity Securities and Use of Proceeds   34
 
  Exhibits   35
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

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PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except for share data)
                 
    September 30,     December 31,  
    2008     2007  
    (Unaudited)          
Assets
               
Current assets:
               
Cash and equivalents
  $ 265     $ 4,018  
Accounts receivable, less allowance for doubtful accounts of $813 and $583
    246,682       166,484  
Unrealized derivative gain
    23,958       53,018  
Deferred tax asset
    28,582       26,907  
Inventory and other
    15,869       11,387  
 
           
Total current assets
    315,356       261,814  
 
           
 
               
Unrealized derivative gain
    1,903       1,082  
Equity method investments
    140,394       113,722  
 
               
Oil and gas properties, successful efforts method
    5,787,886       4,443,577  
Accumulated depletion and depreciation
    (1,115,905 )     (939,769 )
 
           
 
    4,671,981       3,503,808  
 
           
 
               
Transportation and field assets
    121,426       104,802  
Accumulated depreciation and amortization
    (53,189 )     (43,676 )
 
           
 
    68,237       61,126  
 
           
Other assets
    73,323       74,956  
 
           
Total assets
  $ 5,271,194     $ 4,016,508  
 
           
Liabilities
               
Current liabilities:
               
Accounts payable
  $ 301,992     $ 212,514  
Asset retirement obligations
    1,827       1,903  
Accrued liabilities
    49,546       42,964  
Accrued interest
    28,270       17,595  
Unrealized derivative loss
    40,853       30,457  
 
           
Total current liabilities
    422,488       305,433  
 
           
 
               
Bank debt
    550,000       303,500  
Subordinated notes
    1,097,459       847,158  
Deferred tax, net
    744,070       590,786  
Unrealized derivative loss
    19,609       45,819  
Deferred compensation liability
    112,459       120,223  
Asset retirement obligations and other liabilities
 
Commitments and contingencies
    71,156       75,567  
 
               
Stockholders’ equity
               
Preferred stock, $1 par, 10,000,000 shares authorized, none outstanding
           
Common stock, $.01 par, 475,000,000 shares authorized, 155,225,667 issued at September 30, 2008 and 149,667,497 issued at December 31, 2007
    1,552       1,497  
Common stock held in treasury — 233,900 shares at September 30, 2008 and 155,500 shares at December 31, 2007
    (8,557 )     (5,334 )
Additional paid-in capital
    1,687,675       1,386,884  
Retained earnings
    604,604       371,800  
Accumulated other comprehensive loss
    (31,321 )     (26,825 )
 
           
Total stockholders’ equity
    2,253,953       1,728,022  
 
           
Total liabilities and stockholders’ equity
  $ 5,271,194     $ 4,016,508  
 
           
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands except per share data)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     2008     2007  
Revenues
                               
Oil and gas sales
  $ 347,720     $ 214,424     $ 1,002,726     $ 621,636  
Transportation and gathering
    1,537       508       3,890       1,203  
Derivative fair value income (loss)
    272,869       24,974       (49,308 )     11,120  
Other
    544       2,447       20,777       4,749  
 
                       
Total revenues
    622,670       242,353       978,085       638,708  
 
                       
 
                               
Costs and expenses
                               
Direct operating
    36,532       28,003       106,710       78,233  
Production and ad valorem taxes
    15,210       11,316       45,106       32,958  
Exploration
    19,149       6,233       55,204       29,668  
General and administrative
    24,650       18,058       66,000       50,574  
Deferred compensation plan
    (37,515 )     7,761       (9,365 )     28,342  
Interest expense
    25,373       19,935       72,361       56,356  
Depletion, depreciation and amortization
    81,173       57,001       230,206       155,798  
 
                       
Total costs and expenses
    164,572       148,307       566,222       431,929  
 
                       
 
                               
Income from continuing operations before income taxes
    458,098       94,046       411,863       206,779  
 
                               
Income tax provision
                               
Current
    2,374       133       4,209       416  
Deferred
    170,400       34,802       155,172       73,698  
 
                       
 
    172,774       34,935       159,381       74,114  
 
                       
 
                               
Income from continuing operations
    285,324       59,111       252,482       132,665  
 
                               
Discontinued operations, net of taxes
          (196 )           63,593  
 
                       
 
                               
Net income
  $ 285,324     $ 58,915     $ 252,482     $ 196,258  
 
                       
 
                               
Earnings per common share:
                               
Basic — income from continuing operations
  $ 1.87     $ 0.40     $ 1.68     $ 0.92  
— discontinued operations
                      0.45  
 
                       
— net income
  $ 1.87     $ 0.40     $ 1.68     $ 1.37  
 
                       
 
                               
Diluted — income from continuing operations
  $ 1.81     $ 0.39     $ 1.62     $ 0.89  
— discontinued operations
                      0.43  
 
                       
— net income
  $ 1.81     $ 0.39     $ 1.62     $ 1.32  
 
                       
 
                               
Dividends per common share
  $ 0.04     $ 0.03     $ 0.12     $ 0.09  
 
                       
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
                 
    Nine Months Ended  
    September 30,  
    2008     2007  
Operating activities:
               
Net income
  $ 252,482     $ 196,258  
Adjustments to reconcile to net cash provided from operating activities:
               
Income from discontinued operations
          (63,593 )
Income from equity method investments
    (170 )     (1,280 )
Deferred income tax expense
    155,172       73,698  
Depletion, depreciation and amortization
    230,206       155,798  
Unrealized derivative gains
    (1,862 )     (502 )
Mark-to-market losses on oil and gas derivatives not designated as hedges
    4,910       40,171  
Exploration dry hole costs
    9,337       9,072  
Amortization of deferred financing costs and other
    2,137       1,667  
Deferred and stock-based compensation
    13,413       46,770  
(Gain) loss on sale of assets and other
    (19,415 )     2,247  
Changes in working capital:
               
Accounts receivable
    (64,468 )     (29,595 )
Inventory and other
    (5,263 )     (1,672 )
Accounts payable
    2,927       11,597  
Accrued liabilities and other
    20,982       4,894  
 
           
Net cash provided from continuing operations
    600,388       445,530  
Net cash provided from discontinued operations
          10,189  
 
           
Net cash provided from operating activities
    600,388       455,719  
 
           
 
               
Investing activities:
               
Additions to oil and gas properties
    (646,403 )     (601,046 )
Additions to field service assets
    (20,651 )     (20,318 )
Acquisitions, net of cash acquired
    (733,767 )     (309,660 )
Investing activities of discontinued operations
          (7,375 )
Additional investment in other assets
    (50,956 )     (93,313 )
Proceeds from disposal of assets and other
    66,693       234,329  
Purchases of marketable securities held by the deferred compensation plan
    (9,300 )     (34,724 )
Proceeds from the sale of marketable securities held by the deferred compensation plan
    6,605       33,823  
 
           
Net cash used in investing activities
    (1,387,779 )     (798,284 )
 
           
 
               
Financing activities:
               
Borrowings on credit facility
    1,219,000       718,000  
Repayments on credit facility
    (972,500 )     (904,000 )
Debt issuance costs
    (5,710 )     (2,727 )
Dividends paid
    (18,404 )     (13,098 )
Issuance of subordinated notes
    250,000       250,000  
Issuance of common stock
    288,643       292,753  
Treasury stock purchases
    (3,223 )     (5,334 )
Purchases of common stock held by the deferred compensation plan
    (88 )     (69 )
Proceeds from the sale of common stock held by the deferred compensation plan
    5,135       3,291  
Cash overdrafts
    20,785       1,554  
 
           
Net cash provided from financing activities
    783,638       340,370  
 
           
 
               
Net decrease in cash and equivalents
    (3,753 )     (2,195 )
Cash and equivalents at beginning of period
    4,018       2,382  
 
           
Cash and equivalents at end of period
  $ 265     $ 187  
 
           
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited, in thousands)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     2008     2007  
Net income
  $ 285,324     $ 58,915     $ 252,482     $ 196,258  
Other comprehensive (loss) income:
                               
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive (loss) income
    25,670       (2,592 )     53,299       (8,863 )
Change in unrealized deferred hedging gains (losses)
    222,436       3,836       (59,069 )     (16,295 )
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes
          491             1,611  
 
                           
Total comprehensive income
  $ 533,430     $ 60,650     $ 246,712     $ 172,711  
 
                       
See accompanying notes.

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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(1) ORGANIZATION AND NATURE OF BUSINESS
     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 whose common stock is listed and traded on the New York Stock Exchange under the symbol “RRC.”
(2) BASIS OF PRESENTATION
     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2007 Annual Report on Form 10-K filed on February 27, 2008. 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.
     During the first quarter of 2007, we sold our interests in our Austin Chalk properties that we purchased as part of our June 2006 acquisition of Stroud Energy, Inc. (“Stroud”). We also sold our Gulf of Mexico properties at the end of first quarter 2007. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reflected the results of operations of the above divestitures as discontinued operations, rather than a component of continuing operations. See Note 5 for additional information regarding discontinued operations.
(3) NEW ACCOUNTING STANDARDS
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. We adopted SFAS No. 157 effective January 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows. See Note 12 for other disclosures required by SFAS No. 157. In February 2008, the FASB issued FSP SFAS No. 157-2 which delays 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 applies to our asset retirement obligation (ARO), which uses fair value measures at the date incurred to determine our liability. We are currently evaluating the impact of the pending adoption in 2009 of SFAS No. 157 non-recurring fair value measures.
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted SFAS No. 159 effective January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment 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. All investment securities held in our deferred compensation plans are reported in the balance sheet category called other assets and total $41.8 million at September 30, 2008 compared to $51.5 million at December 31, 2007. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as trading securities and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and mark-to-market gains or losses are included in the income statement category called deferred compensation plan expense. For third quarter 2008, interest and dividends were $52,000 and the mark-to-market was a loss of $6.3 million. For the nine months ended September 30, 2008, interest and dividends were $319,000 and the mark-to-market was a loss of $11.5 million. See Note 12 for other disclosures required by SFAS No. 159.

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(4) ACQUISITIONS AND DISPOSITIONS
Acquisitions
     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the closing date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.
     In the third quarter of 2008, we acquired Marcellus Shale unproved properties in a transaction for approximately $210.0 million, subject to typical post-closing adjustments. In the first six months of 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.8 million. After recording asset retirement obligations and transaction costs of $817,000, the purchase price allocated to proved properties was $232.8 million and unproved properties was $99.7 million.
Dispositions
     In first quarter 2008, we sold East Texas properties for proceeds of $64.4 million and recorded a gain of $20.1 million. In first quarter 2007, we sold Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. In first quarter 2007, we also sold Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. We have reflected the results of operations of the Austin Chalk and Gulf of Mexico divestitures as discontinued operations rather than a component of continuing operations for 2007. See Note 5 for additional information.
(5) DISCONTINUED OPERATIONS
     As part of our Stroud acquisition in 2006, we purchased Austin Chalk properties, which we sold in first quarter 2007 for proceeds of $80.4 million. In first quarter 2007, we also sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months and the nine months ended September 30, 2007 are summarized as follows (in thousands):
                 
    Three Months     Nine Months  
    Ended     Ended  
    September 30,     September 30,  
    2007     2007  
Revenues:
               
Oil and gas sales
  $     $ 15,187  
Transportation and gathering
          10  
Other
          310  
(Loss) gain on disposition of assets and other
    (298 )     92,757  
 
           
 
    (298 )     108,264  
 
           
 
               
Costs and expenses:
               
Direct operating
          2,559  
Production and ad valorem taxes
          141  
Exploration and other
    3       215  
Interest expense
          845  
Depletion, depreciation and amortization
          6,672  
 
           
 
    3       10,432  
 
           
 
               
(Loss) income from discontinued operations before income taxes
    (301 )     97,832  
 
               
Income tax (benefit) expense
    (105 )     34,239  
 
           
 
               
(Loss) income from discontinued operations, net of taxes
  $ (196 )   $ 63,593  
 
           
 
               
Production:
               
Crude oil (bbls)
          40,634  
Natural gas (mcf)
          1,990,277  
Total (mcfe)
          2,234,081  

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(6) INCOME TAXES
     Income tax included in continuing operations was as follows (in thousands):
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2008   2007   2008   2007
Income tax expense
  $ 172,774     $ 34,935     $ 159,381     $ 74,114  
Effective tax rate
    37.7 %     37.1 %     38.7 %     35.8 %
     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 September 30, 2008 and September 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. For the nine months ended September 30, 2008, our overall effective tax rate for continuing operations was different than the statutory rate of 35% due to state income taxes, and $2.6 million additional expense for discrete items. For the nine months ended September 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. We expect our effective tax rate to be approximately 38% for the remainder of 2008.
     At December 31, 2007, we had regular tax net operating loss (“NOL”) carryforwards of $204.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $149.7 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2007 was $39.7 million, net of the SFAS No. 123(R) deduction for unrealized benefits. We have $26.9 million of NOLs generated in years before 1998, which are subject to yearly limitations due to IRC Section 382. We do not believe the application of the Section 382 limitations hinders our ability to use such NOLs and therefore, no valuation allowance has been provided. At December 31, 2007, we had AMT credit carryforwards of $777,000 that are not subject to limitation or expiration. We expect to make AMT estimated tax payments of $1.0 million in 2008 and utilize approximately $38.0 million in regular NOL carryforwards and $45.0 million of AMT NOL carryforwards during 2008.

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(7) EARNINGS PER COMMON SHARE
     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):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     2008     2007  
Numerator:
                               
Income from continuing operations
  $ 285,324     $ 59,111     $ 252,482     $ 132,665  
Income from discontinued operations, net of taxes
          (196 )           63,593  
 
                       
Net income
  $ 285,324     $ 58,915     $ 252,482     $ 196,258  
 
                       
 
                               
Denominator:
                               
Weighted average common shares outstanding — basic
    152,765       147,182       150,487       143,508  
Effect of dilutive securities:
                               
Employee stock options, SARs and stock held in the deferred compensation plan
    4,964       5,209       5,409       5,163  
 
                       
Weighted average common shares — diluted
    157,729       152,391       155,896       148,671  
 
                       
 
                               
Earnings per common share:
                               
Basic — income from continuing operations
  $ 1.87     $ 0.40     $ 1.68     $ 0.92  
— discontinued operations
                      0.45  
— net income
    1.87       0.40       1.68       1.37  
 
                               
Diluted — income from continuing operations
  $ 1.81     $ 0.39     $ 1.62     $ 0.89  
— discontinued operations
                      0.43  
— net income
    1.81       0.39       1.62       1.32  
     The weighted average common shares — basic amount excludes 2.2 million shares at September 30, 2008 and 2.0 million shares at September 30, 2007, 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 1.1 million shares for the three months ended September 30, 2008 and 187,000 shares for the nine months ended September 30, 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. SARs for 544,000 shares for the three months ended September 30, 2007 and 282,000 shares for the nine months ended September 30, 2007 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.

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(8) SUSPENDED EXPLORATORY WELL COSTS
     The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2008 and the year ended December 31, 2007 (in thousands):
                 
    September 30,     December 31,  
    2008     2007  
Beginning balance at January 1
  $ 15,053     $ 9,984  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    29,319       14,428  
Reclassifications to wells, facilities and equipment based on determination of proved reserves
    (3,837 )      
Capitalized exploratory well costs charged to expense
    (3,598 )     (8,034 )
Divested wells
          (1,325 )
 
           
Balance at end of period
    36,937       15,053  
Less exploratory well costs that have been capitalized for a period of one year or less
    (32,007 )     (12,067 )
 
           
Capitalized exploratory well costs that have been capitalized for a period greater than one year
  $ 4,930     $ 2,986  
 
           
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    3       2  
 
           
     The $36.9 million of capitalized exploratory well costs at September 30, 2008 was incurred in 2008 ($27.0 million), in 2007 ($7.0 million) and in 2006 ($2.9 million).
(9) INDEBTEDNESS
     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2008 is shown parenthetically). No interest expense was capitalized during the three or the nine months ended September 30, 2008 and 2007.
                 
    September 30,     December 31,  
    2008     2007  
Bank debt (4.0%)
  $ 550,000     $ 303,500  
 
               
Subordinated debt:
               
7.375% Senior Subordinated Notes due 2013, net of discount
    197,874       197,602  
6.375% Senior Subordinated Notes due 2015
    150,000       150,000  
7.5% Senior Subordinated Notes due 2016, net of discount
    249,585       249,556  
7.5% Senior Subordinated Notes due 2017
    250,000       250,000  
7.25% Senior Subordinated Notes due 2018
    250,000        
 
           
Total debt
  $ 1,647,459     $ 1,150,658  
 
           
Bank Debt
     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 $1.0 billion facility amount or the borrowing base. On September 30, 2008, the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. On October 7, 2008, our borrowing base was reconfirmed at $1.5 billion. Our current bank group is comprised of twenty-four commercial banks each holding between 3.0% and 5.3% of the total facility. Of those twenty-four banks, twelve are domestic banks and twelve are foreign banks or wholly owned subsidiaries of foreign banks. The fourth amendment to our credit facility was filed as an exhibit to our Quarterly Report on Form 10-Q filed with the SEC on April 23, 2008. 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 September 30, 2008, the outstanding balance under the bank credit facility was $550.0 million and there was $450.0 million of committed borrowing capacity and an additional $500.0 million of uncommitted borrowing base capacity available. The loan matures October 25, 2012. Borrowing under the bank credit

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facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such data plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under the bank credit facility 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 4.3% for the three months ended September 30, 2008 compared to 6.5% for the three months ended September 30, 2007. The weighted average interest rate on the bank credit facility for the nine months ended September 30, 2008 was 4.7% compared to 6.5% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At September 30, 2008, the commitment fee was 0.25% and the interest rate margin was 1.0%. At October 21, 2008, the interest rate (including applicable margin) was 4.5%.
Senior Subordinated Notes
     In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). Interest on the 7.25% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2013, at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% 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 7.25% 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.
Debt Covenants
     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 September 30, 2008.
     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 September 30, 2008, we were in compliance with these covenants.
(10) ASSET RETIREMENT OBLIGATIONS
     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. A reconciliation of our liability for plugging, abandonment and remediation costs for the nine months ended September 30, 2008 is as follows (in thousands):
         
    Nine Months Ended  
    September 30,  
    2008  
Beginning of period
  $ 75,308  
Liabilities incurred
    2,359  
Liabilities settled
    (851 )
Disposition of wells
    (898 )
Accretion expense
    4,064  
Change in estimate
    (9,420 )
 
     
End of period
  $ 70,562  
 
     

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     Accretion expense is recognized as a component of depreciation, depletion and amortization. The change in estimate category for the nine months ended September 30, 2008 is primarily due to a change in certain of our estimated plugging dates.
(11) CAPITAL STOCK
     In May 2008, at our annual meeting, our shareholders approved an increase to our number of authorized shares of common stock. We now 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 2007:
                 
    Nine   Year
    Months Ended   Ended
    September 30,   December 31,
    2008   2007
Beginning balance
    149,667,497       138,931,565  
Public offering
    4,435,300       8,050,000  
Stock options/SARs exercised
    955,816       2,220,627  
Restricted stock grants
    167,054       408,067  
In lieu of bonuses
          29,483  
Contributed to 401(k) plan
          27,755  
Treasury shares
    (78,400 )      
 
               
 
    5,479,770       10,735,932  
 
               
Ending balance
    155,147,267       149,667,497  
 
               
     In May 2008, we completed a public offering of 4.4 million shares of common stock at $66.38 per share. After underwriting discount and other offering costs of $12.5 million, net proceeds of $281.9 million were used to repay indebtedness on our bank credit facility.
Treasury Stock
     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. In the third quarter 2008, we repurchased 78,400 shares of common stock at an average price of $41.11 per share for a total of $3.2 million.
(12) DERIVATIVE ACTIVITIES
     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 September 30, 2008, we had open swap contracts covering 39.8 Bcf of gas at prices averaging $8.66 per mcf. We also had collars covering 61.2 Bcf of gas at weighted average floor and cap prices of $8.26 to $9.40 per mcf and 3.7 million barrels of oil at weighted average floor and cap prices of $62.98 to $75.89 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 September 30, 2008, was a net unrealized pre-tax loss of $47.1 million. These contracts expire monthly through December 2009.
     The following table sets forth our derivative volumes by year as of September 30, 2008:
                         
                    Average
Period   Contract Type   Volume Hedged   Hedge Price
Natural Gas
                       
2008
  Swaps   155,000 Mmbtu/day     $ 9.17  
2008
  Collars   70,000 Mmbtu/day     $ 8.10 — $10.50  
2009
  Swaps   70,000 Mmbtu/day     $ 8.38  
2009
  Collars   150,000 Mmbtu/day     $ 8.28 — $9.27  
 
Crude Oil
                       
2008
  Collars   9,000 bbl/day     $ 59.34 — $75.48  
2009
  Collars   8,000 bbl/day     $ 64.01 — $76.00  

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     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 loss, which is later transferred to earnings when the hedged 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 September 30, 2008, an unrealized pre-tax derivative loss of $50.4 million was recorded in the balance sheet caption accumulated other comprehensive loss. This loss is expected to be reclassified into earnings in 2008 ($4.4 million) and 2009 ($46.0 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 include $41.2 million and $86.0 million of losses in the three months and the nine months ended September 30, 2008 compared to gains of $4.1 million and $14.1 million in the three months and the nine months ended September 30, 2007. Any ineffectiveness associated with these hedges is reflected in the income statement caption 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 nine months ended September 30, 2008 includes ineffective unrealized gains of $1.9 million compared to gains of $502,000 in the same period of 2007.
     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). As a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of our derivatives, which was designated to our Gulf Coast production, is marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges to market due to the anticipated sale of a portion of our East Texas properties, which was sold in first quarter 2008.
     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 $12.5 million at September 30, 2008 and these swaps expire in 2010.
Derivative Fair Value Income (Loss)
     The following table presents information about the components of derivative fair value income (loss) in the three months and the nine months ended September 30, 2008 and 2007 (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     2008     2007  
Hedge ineffectiveness — realized
  $ (213 )   $     $ 2     $  
— unrealized
    4,553       (28 )     1,862       502  
Change in fair value of derivatives that do not qualify for hedge accounting
    294,317       5,618       (4,910 )     (40,171 )
Realized (loss) gain on settlements — gas (a)
    (18,520 )     19,417       (30,192 )     50,818  
Realized loss on settlements — oil (a)
    (7,268 )     (33 )     (16,070 )     (29 )
 
                       
Derivative fair value income (loss)
  $ 272,869     $ 24,974     $ (49,308 )   $ 11,120  
 
                       
 
(a)   These amounts represent the realized gains and losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category above called the change in fair value of derivatives that do not qualify for hedge accounting.

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     The combined fair value of derivatives included in our consolidated balance sheets as of September 30, 2008 and December 31, 2007 is summarized below (in thousands). We conduct derivative activities with fourteen financial institutions, twelve 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. For example, as of September 30, 2008, we have two counterparties with a total derivative position equal to a net receivable of $16.2 million. This receivable includes an oil collar payable of $10.0 million, which is netted and reported in our derivative receivable.
                 
    September 30,     December 31,  
    2008     2007  
Derivative assets:
               
Natural gas — swaps
  $ 18,923     $ 54,577  
— collars
    12,582       4,916  
— basis swaps
    4,338       1,082  
Crude oil — collars
    (9,982 )     (6,475 )
 
           
 
  $ 25,861     $ 54,100  
 
           
 
Derivative liabilities:
               
Natural gas — swaps
  $ 9,742     $ 6,594  
— collars
    15,050       11,302  
— basis swaps
    8,125       (937 )
Crude oil — collars
    (93,379 )     (93,235 )
 
           
 
  $ (60,462 )   $ (76,276 )
 
           
Fair Value Measurements
     Effective January 1, 2008, we adopted SFAS No. 157, as discussed in Note 3, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which include multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset.
     SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among techniques. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and lowest priority to unobservable inputs (level 3 measurements). The three levels of fair value hierarchy defined by SFAS No. 157 are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Level 2 — Pricing inputs are other than quoted prices in active markets included in either Level 1, which are directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data, which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2008, we have no Level 3 measurements.

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     We use a market approach for our fair value measurements. 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, as set forth in SFAS No. 157 (in thousands):
                                 
            Fair Value Measurements at September 30, 2008 Using
            Quoted Prices in   Significant Other   Significant
    Total Carrying   Active Markets for   Observable   Unobservable
    Value as of   Identical Assets   Inputs   Inputs
    September 30, 2008   (Level 1)   (Level 2)   (Level 3)
Trading securities held in the deferred compensation plans
  $ 41,800     $ 41,800     $     $  
 
Derivatives — swaps
    28,665             28,665        
— collars
    (75,729 )           (75,729 )      
— basis swaps
    12,463             12,463        
     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 September 30, 2008 market values. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services to corroborate market data.
Concentration of Credit Risk
     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 $813,000 at September 30, 2008 and $583,000 at December 31, 2007. 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 fourteen financial institutions, twelve 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 September 30, 2008, our net derivative liability includes a receivable from J. Aron & Company of $618,000 and a liability to Mitsui & Co. for $15.3 million.
     We are a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries, or SemGroup, which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in July 2008. SemGroup purchased oil from us and is currently indebted to us for approximately $1.0 million. We believe that it is probable that a portion of this receivable is uncollectible and have recognized a $450,000 charge in earnings in third quarter 2008.
(13) EMPLOYEE BENEFIT AND EQUITY PLANS
     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. Information with respect to stock option and SARs activities is summarized below:
                 
            Weighted  
            Average  
            Exercise  
    Shares     Price  
Outstanding on December 31, 2007
    7,772,325     $ 17.95  
Granted
    1,142,770       63.61  
Exercised
    (1,201,502 )     14.22  
Expired/forfeited
    (72,833 )     41.55  
 
           
Outstanding on September 30, 2008
    7,640,760     $ 25.14  
 
           

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     The following table shows information with respect to outstanding stock options and SARs at September 30, 2008:
                                           
      Outstanding     Exercisable  
              Weighted-     Weighted-             Weighted-  
              Average     Average             Average  
              Remaining     Exercise             Exercise  
Range of Exercise Prices   Shares     Contractual Life     Price     Shares     Price  
$
  1.29 — $  9.99
    1,870,694       1.94     $ 4.71       1,870,694     $ 4.71  
 
10.00 —   19.99
    1,888,667       1.58       16.25       1,888,667       16.25  
 
20.00 —   29.99
    1,303,586       2.50       24.37       714,836       24.26  
 
30.00 —   39.99
    1,449,403       3.49       33.98       406,953       34.64  
 
40.00 —   49.99
    26,130       4.34       42.60       960       40.54  
 
50.00 —   59.99
    727,115       4.37       58.57       180       58.60  
 
60.00 —   69.99
    28,427       4.62       65.33              
 
70.00 —   75.00
    346,738       4.64       75.00       26,484       75.00  
 
 
                             
    Total   7,640,760       2.61     $ 25.14       4,908,774     $ 14.87  
 
 
                             
     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2008 was $20.65. The fair value of each stock option/SAR granted during 2008 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 2.41%; dividend yield of 0.26%; expected volatility of 41%; and an expected life of 3.5 years.
     As of September 30, 2008, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $158.7 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $138.3 million and 2.03 years. As of September 30, 2008, the number of fully vested awards and awards expected to vest was 7.5 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $24.64 and 2.6 years and the aggregate intrinsic value was $158.0 million. As of September 30, 2008, unrecognized compensation cost related to the awards was $26.9 million, which is expected to be recognized over a weighted average period of 1.1 years. Of the 7.6 million stock option/SARs outstanding at September 30, 2008, 2.9 million are stock options and 4.7 million are SARs.
Restricted Stock Grants
     During the first nine months of 2008, 314,000 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $65.40 with a three-year vesting period and 10,800 shares were granted to our directors at a price of $75.00 with immediate vesting. In the first nine months of 2007, we issued 413,000 shares of restricted stock as compensation to employees at an average price of $34.62 with a three year vesting period and 15,900 shares were granted to our directors at a price of $38.02 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 $10.7 million in the first nine months of 2008 compared to $6.4 million in the nine-month period ended September 30, 2007. As of September 30, 2008, unrecognized compensation cost related to restricted stock awards was $26.7 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). The vesting of these shares is based upon an employees’ continued employment with us.
     A summary of the status of our non-vested restricted stock outstanding at September 30, 2008 is presented below:
                 
            Weighted  
            Average Grant  
    Shares     Date Fair Value  
Non-vested shares outstanding at December 31, 2007
    563,660     $ 30.42  
Granted
    324,949       65.72  
Vested
    (322,402 )     37.39  
Forfeited
    (7,908 )     43.32  
 
           
Non-vested shares outstanding at September 30, 2008
    558,299     $ 46.75  
 
           

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Deferred Compensation Plan
     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 income related to our deferred compensation plan of $37.5 million in the third quarter 2008 and $9.4 million in the first nine months of 2008 compared to mark-to-market expense of $7.8 million and $28.3 million in the same periods of 2007.
(14) SUPPLEMENTAL CASH FLOW INFORMATION
                 
    Nine Months Ended
    September 30,
    2008   2007
    (in thousands)
Non-cash investing and financing activities included:
               
Asset retirement costs capitalized
  $ (7,389 )   $ (438 )
 
               
Net cash provided from operating activities included:
               
Income taxes paid
  $ 4,554     $ 144  
Interest paid
    59,590       56,657  
(15) COMMITMENTS AND CONTINGENCIES
Transportation Contracts
     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 September 30, 2008, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):
         
2008
    $1,729
2009
    7,507
2010
    6,760
2011
    8,000
2012
    5,802
Thereafter
    8,717
     In 2008, we entered into a fifteen-year agreement with a third party to provide gathering, compression and liquids processing in southwestern Pennsylvania. These facilities are expected to process and transport the majority of gas produced by us from wells drilled in the southwestern Pennsylvania area of the Marcellus Shale. The potential effect on future commitments is not included in the table above since our commitments are contingent upon completion of the facilities and throughput volumes. It is estimated that initial throughput capacity will be 30,000 Mmbtu per day. Expansions of the facility are anticipated in the future to substantially enhance this capacity.
     In addition to amounts included in the above table, we have committed to a further delivery of additional gas volumes to a gas pipeline in southwestern Pennsylvania. This commitment is scheduled to increase in increments of 30,000 Mmbtu per day in April 2009 and July 2009 and increase an additional 42,000 Mmbtu per day in January 2010 through 2014. These increases are contingent on certain pipeline modifications being completed.

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Litigation
     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.
(16) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (a)
                 
    September 30,     December 31,  
    2008     2007  
    (in thousands)  
Oil and gas properties:
               
Properties subject to depletion
  $ 5,025,970     $ 4,172,151  
Unproved properties
    761,916       271,426  
 
           
Total
    5,787,886       4,443,577  
Accumulated depreciation, depletion and amortization
    (1,115,905 )     (939,769 )
 
           
Net capitalized costs
  $ 4,671,981     $ 3,503,808  
 
           
 
(a)   Includes capitalized asset retirement costs and associated accumulated amortization.
(17) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT (a)
                 
    Nine Months        
    Ended     Year Ended  
    September 30,     December 31,  
    2008     2007  
    (in thousands)  
Acquisitions:
               
Unproved leasehold
  $ 100,398     $ 4,552  
Proved oil and gas properties
    233,557       253,064  
Asset retirement obligations
    251       3,301  
Acreage purchases (b)
    434,792       78,095  
Development
    572,407       734,987  
Exploration:
               
Drilling
    84,735       40,567  
Expense
    52,076       39,872  
Stock-based compensation expense
    3,128       3,473  
Gas gathering facilities
    25,248       18,655  
 
           
Subtotal
    1,506,592       1,176,566  
 
               
Asset retirement obligations
    (7,389 )     (7,075 )
 
           
Total costs incurred
  $ 1,499,203     $ 1,169,491  
 
           
 
(a)   Includes costs incurred whether capitalized or expensed.
 
(b)   Includes Pennsylvania acreage acquisition for $209.0 million for all deep rights, including the Marcellus Shale.

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(18) ACCOUNTING STANDARDS NOT YET ADOPTED
     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. FSP EITF 03-6-1 is effective for us on January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retroactively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition, we do not expect the application of FSP 03-6-1 to have a significant impact on our reported earnings per share.
     In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS No. 162 to have an impact on our financial statements.
     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 an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for us on January 1, 2009 and will only impact future disclosures about our derivative instruments and hedging activities.
     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 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. We are currently evaluating provisions of this statement.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2007 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 2007 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate only to our continuing operations.
Critical Accounting Estimates and Policies
     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. There have been no significant changes to our critical accounting estimates or policies subsequent to December 31, 2007.
Results of Continuing Operations
Overview
     Total revenues increased $380.3 million, or 157% for third quarter 2008 over the same period of 2007. The increase includes a $133.3 million, or 62% increase in oil and gas sales and a $247.9 million increase in derivative fair value income. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. For third quarter 2008, production increased 19% from the same period of the prior year with the continued success of our drilling program and our acquisitions. Realized prices were higher by 16% in third quarter 2008 when compared to third quarter 2007. We believe oil and gas prices will continue to remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy and the level of oil and gas production in North America and worldwide.
     All of our expenses increased on both an absolute and per mcfe basis during the third quarter 2008, when compared to the same period of 2007, due to higher overall industry costs, higher compensation expense resulting from additional employees, increased salaries and higher levels of activity. While overall costs were higher, the rate of inflation experienced in our industry appears to have moderated for some goods and services. The availability of goods and services continues to be mixed. We continue to experience significant competition for technical and experienced personnel and overall compensation inflation in our industry continues to be high. It is difficult for us to forecast price trends, supply, service or personnel availability, any of which, if changed in an adverse manner would significantly impact both operating costs and capital expenditures. As we continue to have Marcellus wells shut-in waiting on pipeline and processing facilities and we continue to expand our Marcellus operating team to meet the needs of this developing asset, we expect to see continued upward pressure on our cost structure. The initial phase of the pipeline and processing infrastructure is expected to be completed in fourth quarter 2008 with additional expansions set for 2009 and later.

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Oil and Gas Sales, Production and Realized Price Calculation
     Our oil and gas sales vary from quarter to quarter as a result of changes in realized commodity prices or 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 and the nine months ended September 30, 2008 and 2007 (in thousands):
                                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     Change     %     2008     2007     Change     %  
Oil wellhead
  $ 86,506     $ 59,218     $ 27,288       46 %   $ 257,640     $ 161,019     $ 96,621       60 %
Oil hedges realized
    (28,003 )     (5,120 )     (22,883 )     447 %     (76,428 )     (7,068 )     (69,360 )     981 %
 
                                                   
Total oil revenue
    58,503       54,098       4,405       8 %     181,212       153,951       27,261       18 %
 
                                                   
 
                                                               
Gas wellhead
    282,243       138,832       143,411       103 %     775,813       414,758       361,055       87 %
Gas hedges realized
    (13,188 )     9,235       (22,423 )     243 %     (9,540 )     21,136       (30,676 )     145 %
 
                                                   
Total gas revenue
    269,055       148,067       120,988       82 %     766,273       435,894       330,379       76 %
 
                                                   
 
                                                               
NGL
    20,162       12,259       7,903       64 %     55,241       31,791       23,450       74 %
 
                                                   
 
                                                               
Combined wellhead
    388,911       210,309       178,602       85 %     1,088,694       607,568       481,126       79 %
Combined hedges
    (41,191 )     4,115       (45,306 )     1,101 %     (85,968 )     14,068       (100,036 )     711 %
 
                                                   
Total oil and gas sales
  $ 347,720     $ 214,424     $ 133,296       62 %   $ 1,002,726     $ 621,636     $ 381,090       61 %
 
                                                   
     Our production continues to grow through continued drilling success as we place new wells into production and additions from acquisitions. For third quarter 2008, our production volumes increased, from the same period of the prior year, 85% in our Gulf Coast Area, 20% in our Southwestern Area and 13% in our Appalachian Area. For the nine months ended September 30, 2008, our production volumes increased, when compared to the prior year, 75% in our Gulf Coast Area, 22% in our Southwestern Area and 20% in our Appalachian Area. Our production for the three months and the nine months ended September 30, 2008 and 2007 is shown below:
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2008   2007   2008   2007
Production:
                               
Crude oil (bbls)
    759,449       839,863       2,343,138       2,559,992  
NGLs (bbls)
    345,635       284,088       993,366       837,625  
Natural gas (mcf)
    29,053,832       23,261,704       84,029,611       64,469,734  
Total (mcfe) (a)
    35,684,336       30,005,410       104,048,635       84,855,436  
 
                               
Average daily production:
                               
Crude oil (bbls)
    8,255       9,129       8,552       9,377  
NGLs (bbls)
    3,757       3,088       3,625       3,068  
Natural gas (mcf)
    315,803       252,845       306,677       236,153  
Total (mcfe) (a)
    387,873       326,146       379,740       310,826  
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcfe.

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     Our average realized price (including all derivative settlements) received for oil and gas was $9.02 per mcfe in third quarter 2008 compared to $7.79 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 and the nine months ended September 30, 2008 and 2007 are shown below:
                                 
    Three Months Ended   Nine Months Ended,
    September 30,   September 30,
    2008   2007   2008   2007
Average sales prices (wellhead):
                               
Crude oil (per bbl)
  $ 113.91     $ 70.51     $ 109.95     $ 62.90  
NGLs (per bbl)
  $ 58.34     $ 43.15     $ 55.61     $ 37.95  
Natural gas (per mcf)
  $ 9.72     $ 5.97     $ 9.23     $ 6.43  
Total (per mcfe) (a)
  $ 10.90     $ 7.01     $ 10.46     $ 7.16  
 
                               
Average realized price (including derivatives that qualify for hedge accounting):
                               
Crude oil (per bbl)
  $ 77.03     $ 64.41     $ 77.34     $ 60.14  
NGLs (per bbl)
  $ 58.34     $ 43.15     $ 55.61     $ 37.95  
Natural gas (per mcf)
  $ 9.26     $ 6.37     $ 9.12     $ 6.76  
Total (per mcfe) (a)
  $ 9.74     $ 7.15     $ 9.64     $ 7.33  
 
                               
Average realized price (including all derivative settlements):
                               
Crude oil (per bbl)
  $ 67.40     $ 64.37     $ 70.06     $ 60.13  
NGLs (per bbl)
  $ 58.34     $ 43.15     $ 55.61     $ 37.95  
Natural gas (per mcf)
  $ 8.62     $ 7.20     $ 8.77     $ 7.55  
Total (per mcfe) (a)
  $ 9.02     $ 7.79     $ 9.19     $ 7.92  
 
                               
Average NYMEX prices (b)
                               
Oil (per bbl)
  $ 117.83     $ 75.38     $ 113.66     $ 66.23  
Natural gas (per mcf)
  $ 10.08     $ 6.13     $ 9.67     $ 6.88  
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcfe.
 
(b)   Based on average of bid week prompt month prices.

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     Derivative fair value income (loss) includes income of $272.9 million in third quarter 2008 compared to income of $25.0 million in the same period of 2007. 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 caption derivative fair value income (loss). As a result of the sale of our Gulf of Mexico properties in first quarter 2007, the portion of our derivatives that were designated to our Gulf of Mexico production is being marked to market. We have also entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges to market due to the anticipated sale of a portion of our East Texas properties, which occurred in first quarter 2008. The loss of 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 loss. Due to falling commodity prices in the third quarter of 2008 for oil and natural gas, we reported a non-cash unrealized mark-to-market gain from our oil and gas derivatives of $294.3 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 loss for the three months and the nine months ended September 30, 2008 and 2007 (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2008     2007     2008     2007  
Hedge ineffectiveness – realized (c)
  $ (213 )   $     $ 2     $  
– unrealized (a)
    4,553       (28 )     1,862       502  
Change in fair value of derivatives that do not qualify for hedge accounting (a)
    294,317       5,618       (4,910 )     (40,171 )
Realized (loss) gain on settlements – gas (b) (c)
    (18,520 )     19,417       (30,192 )     50,818  
Realized loss on settlements – oil (b) (c)
    (7,268 )     (33 )     (16,070 )     (29 )
 
                       
Derivative fair value income (loss)
  $ 272,869     $ 24,974     $ (49,308 )   $ 11,120  
 
                       
 
(a)   These amounts are unrealized and are not included in average sales price calculations.
 
(b)   These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.
 
(c)   These settlements are included in average realized price calculations.
     Other revenue for third quarter 2008 decreased to $544,000 from $2.4 million in the same period of 2007. Third quarter 2008 includes income from equity method investments of $151,000. Other revenue for third quarter 2007 includes income from equity method investments of $483,000 and $2.2 million received from insurance settlements. Other revenue for the nine months ended September 30, 2008 increased to $20.8 million from $4.7 million in the same period of 2007. The first nine months of 2008 includes a gain of $20.1 million from the sale of certain East Texas properties and income from equity method investments of $170,000. Other revenue for the first nine months of 2007 includes income from equity method investments of $1.3 million and $2.8 million of insurance proceeds.

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     Our costs 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 certain of our expenses on an mcfe basis for the three months and the nine months ended September 30, 2008 and 2007:
                                                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
                            %                           %
    2008   2007   Change   Change   2008   2007   Change   Change
Direct operating expense
  $ 1.02     $ 0.93     $ 0.09       10 %   $ 1.03     $ 0.92     $ 0.11       12 %
Production and ad valorem tax expense
    0.43       0.38       0.05       13 %     0.43       0.39       0.04       10 %
General and administrative expense
    0.69       0.60       0.09       15 %     0.63       0.60       0.03       5 %
Interest expense
    0.71       0.66       0.05       8 %     0.70       0.66       0.04       6 %
Depletion, depreciation and amortization expense
    2.27       1.90       0.37       19 %     2.21       1.84       0.37       20 %
     Direct operating expense increased $8.5 million in third quarter 2008 to $36.5 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells from development and acquisitions and maintain production from our existing properties. We incurred $3.7 million ($0.10 per mcfe) of workover costs in third quarter 2008 versus $1.9 million ($0.06 per mcfe) in 2007. On a per mcfe basis, direct operating expenses for third quarter 2008 increased $0.09 or 10% from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.04 per mcfe), higher personnel and related costs ($0.03 per mcfe) along with higher overall industry costs. Direct operating expenses increased $28.5 million in the first nine months of 2008. We incurred $9.1 million ($0.09 per mcfe) of workover costs in the first nine months of 2008 compared to $5.2 million ($0.06 per mcfe) in the first nine months of 2007. On a per mcfe basis, direct operating expenses for the first nine months 2008 increased $0.11 or 12% from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.03 per mcfe), higher personnel and related costs ($0.02 per mcfe) along with higher overall industry costs, the curtailment of certain Barnett Shale production (primarily in the second quarter of 2008) and the continued infrastructure build-out of our operations in the Marcellus Shale. The following table summarizes direct operating expenses per mcfe for the three months and the nine months ended September 30, 2008 and 2007:
                                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
                            %                             %  
    2008     2007     Change     Change     2008     2007     Change     Change  
Lease operating expense
  $ 0.90     $ 0.86     $ 0.04       5 %   $ 0.92     $ 0.84     $ 0.08       10%  
Workovers
    0.10       0.06       0.04       67 %     0.09       0.06       0.03       50%  
Stock-based compensation (non-cash)
    0.02       0.01       0.01       100 %     0.02       0.02             —%  
 
                                                   
Total direct operating expenses
  $ 1.02     $ 0.93     $ 0.09       10 %   $ 1.03     $ 0.92     $ 0.11       12%  
 
                                                   
     Production and ad valorem taxes are paid based on market prices and not hedged prices. For the third quarter, these taxes increased $3.9 million or 34% from the same period of the prior year due to higher volumes and higher prices. On a per mcfe basis, production and ad valorem taxes increased to $0.43 in third quarter 2008 from $0.38 in the same period of 2007 primarily due to a 55% increase in pre-hedge prices. For the nine months ended September 30, 2008, production and ad valorem taxes increased $12.1 million or 37% from the same period of the prior year due to higher volumes and prices. On a per mcfe basis, production and ad valorem taxes increased to $0.43 in the first nine months of 2008 from $0.39 in the same period of the prior year primarily due to a 46% increase in pre-hedge prices.
     General and administrative expense for third quarter 2008 increased $6.6 million from the third quarter of the prior year due primarily to higher salaries and benefits ($2.6 million), higher stock-based compensation ($831,000), higher legal and professional fees ($542,000), an allowance for bad debt expense of $450,000 and higher office expenses, including rent and information technology. For the nine months ended September 30, 2008, general and administrative expenses increased $15.4 million from the same period of 2007 due primarily to higher salaries and benefits ($6.1 million), higher stock-based compensation ($3.4 million), higher legal fees ($898,000) and higher office expense, including rent and information technology ($1.9 million). The stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense under SFAS No. 123(R). The following table summarizes general and administrative expenses per mcfe for third quarter and the nine months of 2008 and 2007:

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
                            %                             %  
    2008     2007     Change     Change     2008     2007     Change     Change  
General and administrative
  $ 0.53     $ 0.44     $ 0.09       20 %   $ 0.47     $ 0.44     $ 0.03       7 %
Stock-based compensation (non-cash)
    0.16       0.16             %     0.16       0.16             %
 
                                                   
Total general and administrative expenses
  $ 0.69     $ 0.60     $ 0.09       15 %   $ 0.63     $ 0.60     $ 0.03       5 %
 
                                                   
     Interest expense for third quarter 2008 increased $5.4 million to $25.4 million due to the refinancing of certain debt from floating to higher fixed rates in the third quarter 2007 and in the second quarter 2008 and along with higher overall debt balances. In September 2007, we issued $250.0 million of 7.5% Notes due 2017, which also added $4.5 million of interest costs in third quarter 2008 and in May 2008, we issued $250.0 million of 7.25% Notes due 2018, which added $4.5 million of interest costs in third quarter 2008. The proceeds from both issuances 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 third quarter 2008 was $384.6 million compared to $492.6 million for third quarter 2007 and the weighted average interest rates were 4.3% in third quarter 2008 compared to 6.5% in third quarter 2007. Interest expense for the nine months ended September 30, 2008 increased $16.0 million to $72.4 million due to the refinancing of certain debt from floating to higher fixed rates and higher overall debt balances. The issuance of the 7.5% Notes due 2017 added $13.9 million of interest costs for the first nine months of 2008 and the issuance of the 7.25% Notes added $7.6 million to interest costs for the nine months ended September 30, 2008. Average debt outstanding on the credit facility for the nine months ended September 30, 2008 was $425.5 million compared to $452.5 million in the first nine months of 2007. The weighted average interest rate was 4.7% in the first nine months of 2008 compared to 6.5% in the same period of 2007.
     Depletion, depreciation and amortization (“DD&A”) increased $24.2 million, or 42%, to $81.2 million in third quarter 2008 with a 19% increase in production and a 18% increase in depletion rates. On a per mcfe basis, DD&A increased from $1.90 in third quarter 2007 to $2.27 in third quarter 2008. The increase in DD&A per mcfe is related to increasing drilling costs, higher acquisition costs and the mix of our production. The third quarter of 2008 also includes higher acreage impairment/abandonment expense of $2.8 million ($0.06 per mcfe). DD&A expense increased $74.4 million or 48% in the first nine months of 2008 with a 23% increase in production and a 17% increase in depletion rates. The first nine months of 2008 also included higher acreage impairment/abandonment of $9.6 million ($0.08 per mcfe). The following table summarizes DD&A expenses per mcfe for the three months and the nine months ended September 30, 2008 and 2007:
                                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
                            %                             %  
    2008     2007     Change     Change     2008     2007     Change     Change  
Depletion
  $ 2.01     $ 1.70     $ 0.31       18 %   $ 1.97     $ 1.68     $ 0.29       17 %
Depreciation
    0.11       0.10       0.01       10 %     0.10       0.09       0.01       11 %
Accretion
    0.03       0.04       (0.01 )     25 %     0.04       0.05       (0.01 )     20 %
Acreage impairment/abandonment
    0.12       0.06       0.06       100 %     0.10       0.02       0.08       400 %
 
                                                   
Total DD&A expense
  $ 2.27     $ 1.90     $ 0.37       19 %   $ 2.21     $ 1.84     $ 0.37       20 %
 
                                                   
     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense and deferred compensation plan expenses. In the three months and the nine months ended September 30, 2007 and 2008, stock-based compensation represents the amortization of restricted stock grants and expenses related to the adoption of SFAS No. 123(R). In third quarter 2008, stock-based compensation is a component of direct operating expense ($762,000), exploration expense ($1.0 million) and general and administrative expense ($5.5 million) for a total of $7.4 million. In third quarter 2007, stock-based compensation was a component of direct operating expense ($485,000), exploration expense ($931,000) and general and administrative expense ($4.7 million) for a total of $6.2 million. In the nine months ended September 30, 2008, stock-based compensation was a component of direct operating expense ($2.1 million), exploration expense ($3.1 million) and general and administrative expense ($17.1 million) for a total of $22.6 million. In the nine months ended September 30, 2007, stock-based compensation was a component of direct operating expense ($1.4 million), exploration expense ($2.6 million) and general and administrative expense ($13.7 million) for a total of $18.0 million.

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     Exploration expense increased $12.9 million in the third quarter and $25.5 million in the nine month period of 2008 primarily due to higher seismic spending and increased personnel costs. The following table details our exploration-related expenses for the three months and the nine months ended September 30, 2008 and 2007 (in thousands):
                                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
                            %                             %  
    2008     2007     Change     Change     2008     2007     Change     Change  
Dry hole expense
  $ 81     $ 173     $ (92 )     53 %   $ 9,337     $ 9,071     $ 266       3 %
Seismic
    14,090       1,924       12,166       632 %     30,108       8,260       21,848       265 %
Personnel expense
    2,736       2,216       520       23 %     8,799       6,543       2,256       34 %
Stock-based compensation expense
    1,020       930       90       10 %     3,128       2,589       539       21 %
Delay rentals and other
    1,222       990       232       23 %     3,832       3,205       627       20 %
 
                                                   
Total exploration expense
  $ 19,149     $ 6,233     $ 12,916       207 %   $ 55,204     $ 29,668     $ 25,536       86 %
 
                                                   
     Deferred compensation plan expense for the third quarter 2008 decreased $45.3 million from the same period of the prior year due to a decline in our stock price. Our stock price decreased from $65.54 at June 30, 2008 to $42.87 at September 30, 2008. During the same period in the prior year, our stock price increased from $37.41 at June 30, 2007 to $40.66 at September 30, 2007. Deferred compensation plan expense for the nine months ended September 30, 2008 decreased $37.7 million from the same period of the prior year due to decreases in our stock price. Our stock price decreased from $51.36 at December 31, 2007 to $42.87 at September 30, 2008. During the same period of the prior year, our stock price increased from $27.46 at December 31, 2006 to $40.66 at September 30, 2007. 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. The prior year also includes mark-to-market increases or decreases to the marketable securities held in our deferred compensation plans.
     Income tax expense for the third quarter 2008 increased to $172.8 million, reflecting a 387% increase in income from continuing operations before taxes compared to the same period of 2007. The third quarter of 2008 provided for tax expense at an effective rate of 37.7% compared to tax expense at an effective rate of 37.1% in the same period of 2007. For the third quarter 2008, current income taxes of $2.4 million include state income taxes of $2.1 million and $250,000 of federal income taxes. Income tax expense for the nine months ended September 30, 2008 increased to $159.4 million, reflecting a 99% increase in income from continuing operations before taxes compared to the same period of 2007. The nine months ended September 30, 2008 provided for tax expense at an effective rate of 38.7% compared to tax expense at an effective rate of 35.8% in the same period of 2007. For the nine months ended September 30, 2008, current income taxes includes state income taxes of $3.5 million and $750,000 of federal income taxes. The effective tax rate on continuing operations was different than the statutory rate of 35% due to state income taxes. The nine months ended September 30, 2008 also includes $2.6 million of additional tax expense for discrete items. We expect our effective tax rate to be approximately 38% for the remainder of 2008.
     Discontinued operations in the third quarter and the first nine months of 2007 include the operating results related to our Gulf of Mexico properties and Austin Chalk properties sold in first quarter 2007.
Liquidity and Capital Resources
     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. The debt and equity capital markets have recently exhibited adverse conditions. Continued volatility in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. At this point, we do not believe our liquidity has been materially affected by the recent events in the global financial markets and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of our twenty-four lenders in our bank credit facility. To date we have experienced no disruptions in our ability to access the bank credit facility. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment. On October 7, 2008, our bank group reconfirmed our $1.5 billion borrowing base and our $1.0 billion commitment amount. We believe our maximum bank credit facility borrowing capacity exceeds $1.5 billion and is sufficient to absorb a decline in commodity prices or any changes in bank lending practices.
     During the nine months ended September 30, 2008, our cash provided from continuing operations was $600.4 million and we spent $718.0 million on capital expenditures and $733.8 million on acquisitions. During this period, financing activities provided net cash of $783.6 million. At September 30, 2008, we had $265,000 in cash, total assets of $5.3 billion and a debt-to-capitalization ratio of 42.2%. Long-term debt at September 30, 2008 totaled $1.6 billion including $550.0 million of bank credit facility debt and $1.1 billion of senior subordinated notes. Available committed borrowing capacity under the bank credit facility at September 30, 2008 was $450.0 million.

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     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. A material drop in 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 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.
Credit Arrangements
     On September 30, 2008, the bank credit facility had a $1.5 billion borrowing base and a $1.0 billion facility amount. The borrowing base represents an amount approved by the bank group that can be borrowed based on our assets, while our $1.0 billion facility amount is the amount the banks have committed to fund pursuant to the credit agreement. Remaining credit availability is $359.0 million on October 21, 2008. Our bank group is comprised of twenty-four commercial banks, with no one bank holding more than 5.3% 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 $1.0 billion commitment up to the $1.5 billion borrowing base and also allows 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 September 30, 2008. Please see Note 9 to our consolidated financial statements for additional information.
Cash Flow
     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 September 30, 2008, we have entered into hedging agreements covering 25.7 Bcfe for 2008 and 97.8 Bcfe for 2009.
     Net cash provided from continuing operations for the nine months ended September 30, 2008 was $600.4 million compared to $455.7 million in the nine months ended September 30, 2007. Cash flow from operations was higher than the prior year due to higher production from development activity and acquisitions. 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 nine months ended September 30, 2008 was a negative $45.8 million compared to a negative $14.8 million in the same period of the prior year.
     Net cash used in investing for the nine months ended September 30, 2008 was $1.4 billion compared to $798.3 million in the same period of 2007. The 2008 period included $646.4 million of additions to oil and gas properties and $733.8 million of acquisitions, offset by proceeds of $66.7 million from asset sales. Acquisitions for the first nine months 2008 include the purchase of producing and non-producing Barnett Shale properties for $331.8 million and the acquisition of certain Marcellus Shale leasehold acreage for $210.0 million. The 2007 period included $601.0 million of additions to oil and gas properties and $403.0 million of acquisitions and other investments, offset by proceeds of $234.3 million from asset sales.

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     Net cash provided from financing for the nine months ended September 30, 2008 was $783.6 million compared to $340.4 million in the first nine months of 2007. This increase was primarily due to the borrowings on our bank credit facility. During the first nine months of 2008, total debt increased $496.8 million. In 2008, the Board of Directors approved a share repurchase program authorizing the purchase of up to $10.0 million of our common stock. During the nine months ended September 30, 2008, we expended $3.2 million to acquire 78,400 shares of treasury stock.
Dividends
     On September 1, 2008, the Board of Directors declared a dividend of four cents per share ($6.2 million) on our common stock, which was paid on September 30, 2008 to stockholders of record at the close of business on September 16, 2008.
Capital Requirements, Contractual Cash Obligations and Off-Balance Sheet Arrangements
     The 2008 capital budget is currently set at $1.3 billion (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow, asset sales and borrowings under our bank credit facility. Acquisitions during the year include $331.8 million purchase of proved and unproved properties in the Barnett Shale and $210.0 million purchase of unproved properties in the Marcellus Shale which were funded with borrowings under the credit facility and proceeds received from an equity offering. For the nine months ended September 30, 2008, $712.3 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 depending on commodity prices and cash flow. During the last few years, we have increased our capital budget as our cash flow has increased. With the recent significant decline in commodity prices, we will likely decrease our capital budget for 2009.
     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation commitments and other liabilities. Since December 31, 2007, the material changes to our contractual obligations included a $496.8 million increase in long-term debt, a $15.8 million decrease in our derivative obligations, a $4.7 million decrease in our asset retirement obligations 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 September 30, 2008, future minimum transportation fees under our gas transportation commitments were as follows (in thousands):
   
2008
$1,729
2009
7,507
2010
6,760
2011
8,000
2012
5,802
Thereafter
8,717
     In 2008, we entered into a fifteen-year agreement with a third party to provide gathering, compression and liquids processing in southwestern Pennsylvania. These facilities are expected to process and transport the majority of gas produced by us from wells drilled in the southwestern Pennsylvania area of the Marcellus Shale. The potential effect on future commitments is not included in the above table since our commitments are contingent upon completion of the facilities. It is estimated that initial throughput capacity will be 30,000 Mmbtu per day. Expansions of the facility are anticipated in the future to substantially enhance this capacity.
     In addition to amounts included in the above table, we have committed to a further delivery of additional gas volumes to a gas pipeline in southwestern Pennsylvania. This commitment is scheduled to increase in increments of 30,000 Mmbtu per day in April 2009 and July 2009 and increase an additional 42,000 Mmbtu per day in January 2010 through 2014. These increases are contingent on certain pipeline modifications being completed.
Other Contingencies
     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.

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Hedging – Oil and Gas Prices
     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 September 30, 2008, we had open swaps contracts covering 39.8 Bcf of gas at prices averaging $8.66 per mcf. We also have collars covering 61.2 Bcf of gas at weighted average floor and cap prices of $8.26 and $9.40 per mcf and 3.7 million barrels of oil at weighted average floor and cap prices of $62.98 and $75.89 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 New York Mercantile Exchange (“NYMEX”), on September 30, 2008 was a net unrealized pre-tax loss of $47.1 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 nine months of 2008, oil and gas sales included realized hedging losses of $86.0 million compared to gains of $14.1 million in the same period of 2007.
     At September 30, 2008, the following commodity derivative contracts were outstanding:
             
            Average
Period   Contract Type   Volume Hedged   Hedge Price
Natural Gas
           
2008   Swaps   155,000 Mmbtu/day   $9.17
2008   Collars   70,000 Mmbtu/day   $8.10 — $10.50
2009   Swaps   70,000 Mmbtu/day   $8.38
2009   Collars   150,000 Mmbtu/day   $8.28 — $9.27
             
Crude Oil            
2008   Collars   9,000 bbl/day   $59.34 — $75.48
2009   Collars   8,000 bbl/day   $64.01 — $76.00
     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. Under this method, the contracts are carried at their fair value on our balance sheet under the captions unrealized derivative gains and losses. We recognize all unrealized and realized gains and losses related to these contracts in our income statement caption called derivative fair value income (loss).
     As a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of derivatives, which were designated to our Gulf Coast production, are marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges designated as Permian production to market due to the anticipated sale of a portion of our East Texas Permian properties that occurred in first quarter 2008. Derivatives that no longer qualify for hedge accounting are accounted for using the mark-to-market accounting method described above. As of September 30, 2008, derivatives on 50.4 Bcfe no longer qualify or are not designated for hedge accounting.
     In addition to the swaps and collars above, we entered into basis swap agreements that do not qualify as hedges for hedge accounting purposes and are marked to market. The price we receive for our production can be less than 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 the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $12.5 million at September 30, 2008.
Interest Rates
     At September 30, 2008, we had $1.6 billion of debt outstanding. Of this amount, $1.1 billion bore interest at fixed rates averaging 7.3%. Bank debt totaling $550.0 million bears interest at floating rates, which averaged 4.0% at September 30, 2008. The 30 day LIBOR rate on September 30, 2008 was 3.9%.

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Debt Ratings
     We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investor Services, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s rating for us is BB with a positive outlook. Moody’s rating for us is Ba3 with a stable outlook. We believe that S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels, asset, and proved reserve mix. A reduction in our debt ratings could negatively impact our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.
Inflation and Changes in Prices
     Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During third quarter 2008, we received an average of $113.91 per barrel of oil and $9.72 per mcf of gas before derivative contracts compared to $70.51 per barrel of oil and $5.97 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to moderate for the remainder of 2008 and into 2009.
Accounting Standards Not Yet Adopted
     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. FSP EITF 03-6-1 is effective for us January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retroactively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition, we do not expect the application of FSP 03-6-1 to have a significant impact on our reported earnings per share.
     In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS No. 162 to have an impact on our financial statements.
     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). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for us January 1, 2009 and will only impact future disclosures about our derivative instruments and hedging activities.
     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 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. We are currently evaluating provisions of this statement.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposures. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.
Financial Market Risk
     The debt and equity markets have recently exhibited adverse conditions. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. At this point, we do not believe our liquidity has been materially affected by the recent events in the global markets and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of our twenty-four lenders in the bank credit facility.
Market Risk
     Our major market risk is exposure to oil and gas prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Oil and gas prices have been volatile and unpredictable for many years.
Commodity Price Risk
     We periodically enter into derivative arrangements with respect to our oil and gas production. These arrangements are intended to reduce the impact of oil and gas price fluctuations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which assume a minimum floor price and a predetermined ceiling price. Historically, we applied hedge accounting to derivatives utilized to manage price risk associated with our oil and gas production. Accordingly, we recorded change in the fair value of our swap and collar contracts under the balance sheet caption accumulated other comprehensive income (loss) and into oil and gas sales when the forecasted sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge is reported currently each period under the income statement caption derivative fair value income. 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. Under this method, the contracts are carried at their fair value on our consolidated balance sheet under the captions unrealized derivative gains and losses. We recognize all unrealized and realized gains and losses related to these contracts in our income statement under the caption derivative fair value income (loss). Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Our derivative counterparties include fourteen financial institutions, twelve of which are in our bank group. Mitsui & Co. and J. Aron & Company are the two counterparties not in our bank group. At September 30, 2008, our net derivative liability includes a receivable from J. Aron & Company of $618,000 and a liability to Mitsui & Co. for $15.3 million. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.
     As of September 30, 2008, we had swaps in place covering 39.8 Bcf of gas. We also had collars covering 61.2 Bcf of gas and 3.7 million barrels of oil. These contracts expire monthly through December 2009. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of September 30, 2008, approximated a net unrealized pre-tax loss of $47.1 million.

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     At September 30, 2008, the following commodity derivative contracts were outstanding:
                 
Period   Contract Type   Volume Hedged   Average Hedge Price   Fair Market Value
                (in thousands)
Natural Gas                
2008   Swaps   155,000 Mmbtu/day   $9.17   $  22,822
2008   Collars   70,000 Mmbtu/day   $8.10 — $10.50   $    4,822
2009   Swaps   70,000 Mmbtu/day   $8.38   $    5,843
2009   Collars   150,000 Mmbtu/day   $8.28 — $9.27   $  22,811
                 
Crude Oil                
2008   Collars   9,000 bbl/day   $59.34 — $75.48   $(21,262)
2009   Collars   8,000 bbl/day   $64.01 — $76.00   $(82,100)
Other Commodity Risk
     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the collars and swaps detailed 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 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 the basis adjustments. The fair value of the basis swaps was a net realized pre-tax gain of $12.5 million at September 30, 2008.
     In the first nine months of 2008, a 10% reduction in oil and gas prices, excluding amounts fixed through designated hedging transactions, would have reduced revenue by $109.1 million. If oil and gas future prices at September 30, 2008 declined 10%, the unrealized hedging activity would be a positive $107.6 million.
     Interest rate risk. At September 30, 2008, we had $1.6 billion of debt outstanding. Of this amount, $1.1 billion bore interest at fixed rates averaging 7.3%. Senior debt totaling $550.0 million bore interest at floating rates averaging 4.0%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $5.5 million.
Item 4. CONTROLS AND PROCEDURES
     As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 or the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting us to material information required to be included in this report. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II – OTHER INFORMATION
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     The following summarizes purchases of our common stock during the third quarter of 2008:
                             
                    Total number of shares   Maximum number of
                    purchased as part of   shares that may yet be
    Total number of   Average price   publicly announced   purchased under the
Period   shares purchased   paid per share   plans or programs (1)   plan or programs (2)
August 8-14
    78,400     $ 41.11         158,082  
 
(1)   We had a repurchase program approved by the Board of Directors in May 2008 for the repurchase of up to $10.0 million of our common stock.
 
(2)   Assumes purchase price of $42.87, the closing price of our stock on September 30, 2008.

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Item 6. Exhibits
(a) EXHIBITS
     
Exhibit    
Number   Description
 
   
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2007)
 
   
3.2
  Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004)
 
   
31.1*
  Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
31.2*
  Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32.1**
  Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
   
32.2**
  Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
*   filed herewith
 
**   furnished herewith

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  RANGE RESOURCES CORPORATION
 
 
  By:   /s/ ROGER S. MANNY    
    Roger S. Manny   
    Executive Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)   
 
October 22, 2008

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     Exhibit index
     
Exhibit    
Number   Description
 
   
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2007)
 
   
3.2
  Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004)
 
   
31.1*
  Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
31.2*
  Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32.1**
  Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
   
32.2**
  Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
*   filed herewith
 
**   furnished herewith

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