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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, 2007
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)
Registrant’s Telephone Number, Including Area Code
(817) 870-2601
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 or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer “in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer   þ     Accelerated Filer   o      Non-Accelerated Filer   o
     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
149,193,657 Common Shares were outstanding on October 22, 2007.
 
 

 


 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended September 30, 2007
     Unless the context otherwise indicates, all references in this report to “Range” “we” “us” or “our” are to Range Resources Corporation and its subsidiaries.
TABLE OF CONTENTS
 
 Certification by the President and CEO Pursuant to Section 302
 Certification by the Chief Financial Officer Pursuant to Section 302
 Certification by the President and CEO Pursuant to Section 906
 Certification by the Chief Financial Officer Pursuant to Section 906
             
      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  
 
 
  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     31  
 
  Controls and Procedures     33  
 
 
           
 
PART II – OTHER INFORMATION        
 
 
           
  Exhibits     34  

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PART I – Financial Information
ITEM 1. – Financial Statements
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands, except per share data)
                 
    September 30,     December 31,  
    2007     2006  
Assets
               
Current assets:
               
Cash and equivalents
  $ 187     $ 2,382  
Accounts receivable, less allowance for doubtful accounts of $459 and $746
    146,618       125,421  
Assets held for sale
          79,304  
Assets of discontinued operation
          78,161  
Unrealized derivative gain
    72,153       93,588  
Inventory and other
    12,102       10,069  
 
           
Total current assets
    231,060       388,925  
 
           
 
               
Unrealized derivative gain
    10,590       61,068  
Equity method investments
    111,735       13,618  
 
Oil and gas properties, successful efforts method
    4,286,179       3,359,093  
Accumulated depletion and depreciation
    (924,155 )     (751,005 )
 
           
 
    3,362,024       2,608,088  
 
           
Transportation and field assets
    99,256       80,066  
Accumulated depreciation and amortization
    (40,577 )     (32,923 )
 
           
 
    58,679       47,143  
 
           
Other assets
    74,338       68,832  
 
           
Total assets
  $ 3,848,426     $ 3,187,674  
 
           
Liabilities
               
Current liabilities:
               
Accounts payable
  $ 182,483     $ 171,914  
Asset retirement obligation
    1,251       3,853  
Accrued liabilities
    40,785       30,026  
Liabilities of discontinued operation
          28,333  
Accrued interest
    11,791       12,938  
Unrealized derivative loss
    7,657       4,621  
 
           
Total current liabilities
    243,967       251,685  
 
           
 
Bank debt
    266,000       452,000  
Subordinated notes
    847,062       596,782  
Deferred tax, net
    562,703       468,643  
Unrealized derivative loss
    4,967       266  
Deferred compensation liability
    133,962       90,094  
Asset retirement obligation and other liabilities
    80,953       72,043  
Commitments and contingencies
               
 
               
Stockholders’ equity
               
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding
           
Common stock, $.01 par, 250,000,000 shares authorized, 148,963,308 issued at September 30, 2007 and 138,931,565 issued at December 31, 2006
    1,490       1,389  
Common stock held in treasury, 155,500 shares at September 30, 2007, none at December 31, 2006 – at cost
    (5,334 )      
Additional paid-in capital
    1,392,441       1,079,994  
Retained earnings
    343,473       160,313  
Common stock held by employee benefit trust, 2,185,898 shares at September 30, 2007 and 1,853,279 shares at December 31, 2006 - at cost
    (36,232 )     (22,056 )
Accumulated other comprehensive income
    12,974       36,521  
 
           
Total stockholders’ equity
    1,708,812       1,256,161  
 
           
Total liabilities and stockholders’ equity
  $ 3,848,426     $ 3,187,674  
 
           
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,  
    2007     2006     2007     2006  
Revenues (See Note 2)
                               
Oil and gas sales
  $ 214,424     $ 153,054     $ 621,636     $ 443,143  
Transportation and gathering
    508       1,015       1,203       1,933  
Derivative fair value income
    25,002       65,306       10,618       119,914  
Other
    2,419       250       5,251       3,255  
 
                       
Total revenues
    242,353       219,625       638,708       568,245  
 
                       
 
Costs and expenses
                               
Direct operating
    28,003       22,336       78,233       57,402  
Production and ad valorem taxes
    11,316       9,874       32,958       27,970  
Exploration
    6,233       16,508       29,668       33,193  
General and administrative
    18,058       12,170       50,574       36,014  
Deferred compensation plan
    7,761       (2,638 )     28,342       (347 )
Interest expense
    19,935       16,389       56,356       38,266  
Depletion, depreciation and amortization
    57,001       40,606       155,798       106,252  
 
                       
Total costs and expenses
    148,307       115,245       431,929       298,750  
 
                       
 
Income from continuing operations before income taxes
    94,046       104,380       206,779       269,495  
 
Income tax provision
                               
Current
    133       615       416       1,815  
Deferred
    34,802       38,707       73,698       99,533  
 
                       
 
    34,935       39,322       74,114       101,348  
 
                       
 
Income from continuing operations
    59,111       65,058       132,665       168,147  
 
Discontinued operations, net of income taxes
    (196 )     (13,728 )     63,593       (9,872 )
 
                       
 
Net income
  $ 58,915     $ 51,330     $ 196,258     $ 158,275  
 
                       
 
Earnings per common share:
                               
Basic — income from continuing operations
  $ 0.40     $ 0.47     $ 0.92     $ 1.27  
- discontinued operations
          (0.10 )     0.45       (0.07 )
 
                       
- net income
  $ 0.40     $ 0.37     $ 1.37     $ 1.20  
 
                       
 
Diluted — income from continuing operations
  $ 0.39     $ 0.46     $ 0.89     $ 1.22  
- discontinued operations
          (0.10 )     0.43       (0.07 )
 
                       
- net income
  $ 0.39     $ 0.36     $ 1.32     $ 1.15  
 
                       
 
Dividends per common share
  $ 0.03     $ 0.02     $ 0.09     $ 0.06  
 
                       
 
Weighted average common shares outstanding:
                               
 
Basic
    147,182       136,983       143,508       132,426  
 
                       
Diluted
    152,391       142,022       148,671       137,466  
 
                       
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
                 
    Nine Months Ended  
    September 30,  
    2007     2006  
Operating activities:
               
Net income
  $ 196,258     $ 158,275  
Adjustments to reconcile to net cash provided from operating activities:
               
(Gains)/losses from discontinued operations
    (63,593 )     9,872  
(Gains)/losses from equity method investments
    (1,280 )     61  
Deferred income tax expense
    73,698       99,533  
Depletion, depreciation and amortization
    155,798       106,252  
Unrealized derivative gains
    (502 )     (3,178 )
Mark-to-market (gains)/losses on oil and gas derivatives not designated as hedges
    40,171       (83,734 )
Exploration dry hole costs
    9,072       9,291  
Amortization of deferred issuance costs and other
    1,667       1,221  
Non-cash compensation
    46,770       13,839  
Loss on sale of assets and other
    2,247       1,009  
Changes in working capital, net of amounts from business acquisitions:
               
Accounts receivable
    (29,595 )     29,323  
Inventory and other
    (1,672 )     (1,911 )
Accounts payable
    11,597       (17,801 )
Accrued liabilities and other
    4,894       (2,387 )
 
           
Net cash provided from continuing operations
    445,530       319,665  
Net cash provided from discontinued operations
    10,189       28,475  
 
           
Net cash provided from operating activities
    455,719       348,140  
 
           
 
               
Investing activities:
               
Additions to oil and gas properties
    (601,046 )     (328,362 )
Additions to field service assets
    (20,318 )     (10,033 )
Acquisitions, net of cash acquired
    (309,660 )     (336,735 )
Investment in equity method affiliates and other
    (93,313 )     (21,008 )
Purchases of marketable securities held by deferred compensation plan
    (34,724 )      
Proceeds from sales of marketable securities held by deferred compensation plan
    33,823        
Proceeds from disposal of assets
    25       166  
Proceeds from disposal of discontinued operations
    234,304        
Investing activities of discontinued operations
    (7,375 )     (18,630 )
 
           
Net cash used in investing activities
    (798,284 )     (714,602 )
 
           
 
               
Financing activities:
               
Borrowings on credit facility
    718,000       650,500  
Repayments on credit facility
    (904,000 )     (535,000 )
Debt issuance costs
    (2,727 )     (5,560 )
Dividends paid
    (13,098 )     (8,021 )
Issuance of common stock, net
    292,753       12,544  
Issuance of subordinated notes
    250,000       249,500  
Proceeds from sales of common stock held by deferred compensation plan and other
    4,845        
Purchases of common stock held by deferred compensation plan and other treasury stock purchases
    (5,403 )      
 
           
Net cash provided from financing activities
    340,370       363,963  
 
           
 
               
Net decrease in cash and equivalents
    (2,195 )     (2,499 )
Cash and equivalents at beginning of period
    2,382       4,750  
 
           
Cash and equivalents at end of period
  $ 187     $ 2,251  
 
           
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,  
    2007     2006     2007     2006  
Net income
  $ 58,915     $ 51,330     $ 196,258     $ 158,275  
Net deferred hedge gains/(losses), net of tax:
                               
Contract settlements reclassified to income
    18,337       14,511       (8,863 )     50,130  
Change in unrealized deferred hedging gains/(losses)
    (17,093 )     66,692       (16,295 )     108,672  
Change in unrealized gains on securities held by deferred compensation plan, net of taxes
    491       433       1,611       191  
 
                       
Comprehensive income
  $ 60,650     $ 132,966     $ 172,711     $ 317,268  
 
                       
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. We are a Delaware corporation whose common stock is traded on the New York Stock Exchange.
(2) BASIS OF PRESENTATION
     Certain disclosures have been condensed or omitted from these statements. Therefore, these interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2006 Annual Report on Form 10-K and our Form 8-K filed on June 19, 2007. 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 for complete financial statements. Certain reclassifications have been made to the presentation of prior periods to conform to the current year presentation, which includes the presentation of our Gulf of Mexico operations as discontinued operations and the reclassification of settled derivatives that do not qualify for hedge accounting from oil and gas sales to derivative fair value income. We previously had been reclassifying the realized gain or loss from non-hedge derivatives into oil and gas sales. This reclassification will now present all gains and losses, realized and unrealized, on the derivative fair value income line in our consolidated statements of operations. These are changes to presentation only and do not affect previously reported net income, total revenues or earnings per share. The following table details the affected financial statement line items related to the revenue reclassification for the periods previously reported, including the six months ended June 30, 2007 and the nine months ended September 30, 2006 (in thousands):
                         
    Three Months Ended   Three Months Ended   Six Months Ended
    March 31, 2007   June 30, 2007   June 30, 2007
As reported:
                       
Oil and gas sales
  $ 217,026     $ 221,591     $ 438,617  
Mark-to-market on oil and gas derivatives
    (66,111 )     20,322       (45,789 )
 
                 
 
  $ 150,915     $ 241,913     $ 392,828  
 
                 
 
                       
As reclassified:
                       
Oil and gas sales
  $ 193,316     $ 213,896     $ 407,212  
Derivative fair value income
    (42,401 )     28,017       (14,384 )
 
                 
 
  $ 150,915     $ 241,913     $ 392,828  
 
                 
                                 
    Three Months Ended   Three Months Ended   Three Months Ended   Nine Month Ended
    March 31, 2006   June 30, 2006   September 30, 2006   September 30, 2006
As reported:
                               
Oil and gas sales
  $ 166,555     $ 149,358     $ 163,410     $ 479,323  
Mark-to-market on oil and gas derivatives
    11,281       17,503       54,950       83,734  
 
                       
 
  $ 177,836     $ 166,861     $ 218,360     $ 563,057  
 
                       
 
As reclassified:
                               
Oil and gas sales
  $ 150,658     $ 139,431     $ 153,054     $ 443,143  
Derivative fair value income
    27,178       27,430       65,306       119,914  
 
                       
 
  $ 177,836     $ 166,861     $ 218,360     $ 563,057  
 
                       

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     During the first quarter of 2007, we sold our interests in our Austin Chalk properties that we purchased as part of the Stroud acquisition. We also sold our Gulf of Mexico properties at the end of the first quarter of 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 4 for additional information regarding discontinued operations.
(3) ACQUISITIONS AND DISPOSITIONS
Acquisitions
     In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a joint development plan with Equitable Resources, Inc (“Equitable”). As a result of this transaction, Equitable and Range equalized their working interests in the Nora field, including producing wells, undrilled acreage and gathering systems. Range retained its separately owned royalty interest in the Nora field. Equitable will operate the producing wells, manage the drilling operations of all future coal bed methane wells and manage the gathering system. Range will oversee the drilling of formations below the coal bed methane formations, including tight gas, shale and deeper formations. A newly formed limited liability corporation will hold the investment in the gathering system which is owned 50% by Equitable and 50% by Range. All business decisions require a unanimous consent of both parties. The gathering system investment is accounted for as an equity method investment. Including estimated transaction costs, we paid $278.6 million which includes $188.3 million allocated to oil and gas properties, $93.4 million allocated to our equity method investment and a $3.1 million asset retirement obligation. No pro forma information has been provided as the acquisition was not considered significant.
     In June 2006, we acquired Stroud Energy, Inc. (“Stroud”), a private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. To acquire Stroud, we paid $171.5 million of cash and issued 6.5 million shares of our common stock.
     The following table summarizes the final purchase price allocation to assets acquired and liabilities assumed at closing in the Stroud acquisition (in thousands):
         
Cash paid (including transaction costs)
  $ 171,529  
6.5 million shares of common stock (at fair value of $27.26 per share)
    177,641  
Stock options assumed (652,000 options)
    9,478  
Debt retired
    106,700  
 
     
Total
  $ 465,348  
 
     
 
Allocation of purchase price:
       
Working capital deficit
  $ (13,557 )
Other long-term assets
    55  
Oil and gas properties
    487,345  
Assets held for sale
    140,000  
Deferred income taxes
    (147,062 )
Asset retirement obligation
    (1,433 )
 
     
Total
  $ 465,348  
 
     

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Pro Forma
          The following unaudited pro forma data includes the results of operations as if the Stroud acquisition had been consummated at the beginning of 2006. See also Note 4 for additional information on discontinued operations. The pro forma data are based on historical information and do not necessarily reflect the actual results that would have occurred, nor are they necessarily indicative of future results of operations (in thousands, except per share data).
         
    Nine Months
    Ended
    September 30,
    2006
Revenues
  $ 602,920  
Income from continuing operations
    167,570  
Net income
    161,571  
 
       
Per share data:
       
Income from continuing operations – basic
  $ 1.22  
Income from continuing operations – diluted
    1.18  
 
       
Net income – basic
  $ 1.18  
Net income – diluted
    1.14  
Dispositions
          In February 2007, we sold the Stroud Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. These properties were originally acquired in mid —2006 as part of our Stroud acquisition and were classified as assets held for sale since the acquisition date. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. The properties included any properties within the waters of the Gulf of Mexico (either state or federal). We have reflected the results of operations of the above divestitures as discontinued operations rather than a component of continuing operations. See Note 4 for additional information.
(4) DISCONTINUED OPERATIONS
          As part of the Stroud acquisition, we purchased Austin Chalk properties in East Texas which we sold in February 2007 for proceeds of $80.4 million. These Austin Chalk properties were classified as Assets Held for Sale on our balance sheet as of December 31, 2006 and were reflected in discontinued operations in our consolidated statement of operations in the twelve months ended December 31, 2006. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. All prior year periods include the reclassification of our Gulf of Mexico operations to discontinued operations.

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          Discontinued operations for the three months and the nine months ended September 30, 2007 and 2006 are summarized as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
Revenues:
                               
Oil and gas sales
  $     $ 18,959     $ 15,187     $ 38,022  
Transportation and gathering
          19       10       76  
Other
          (1 )     310       (2 )
Gain (loss) on disposition of assets and other
    (298 )           92,757        
 
                       
 
    (298 )     18,977       108,264       38,096  
 
                       
 
                               
Costs and expenses:
                               
Direct operating
          2,923       2,559       8,113  
Production and ad valorem taxes
          409       141       777  
Exploration and other
    3       179       215       1,349  
Interest expense
          1,259       845       1,936  
Depletion, depreciation and amortization
          5,652       6,672       11,406  
Impairment
          30,362             30,362  
 
                       
 
    3       40,784       10,432       53,943  
 
                       
 
                               
Income (loss) from discontinued operations before income taxes
    (301 )     (21,807 )     97,832       (15,847 )
 
Income tax expense (benefit)
    (105 )     (8,079 )     34,239       (5,975 )
 
                       
 
Income (loss) from discontinued operations, net of taxes
  $ (196 )   $ (13,728 )   $ 63,593     $ (9,872 )
 
                       
 
                               
Production:
                               
Crude oil (bbls)
          43,323       40,634       100,515  
Natural gas (mcf)
          2,734,521       1,990,277       5,187,183  
Total (mcfe)
          2,994,459       2,234,081       5,790,273  
          Due to falling oil and gas prices since the acquisition, we recognized a $30.4 million impairment on the Austin Chalk properties during the three months ended September 30, 2006. Ultimately, for the twelve months ended December 31, 2006, we recognized an impairment of $74.9 million.
(5) INCOME TAXES
          Income tax included in continuing operations was as follows (in thousands):
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2007   2006   2007   2006
Income tax expense
  $ 34,935     $ 39,322     $ 74,114     $ 101,348  
Effective tax rate
    37.1 %     37.7 %     35.8 %     37.6 %
          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 or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months and nine months ended September 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to state income taxes and an increase in our deferred tax assets related to state tax credit carryovers. The nine months ended September 30, 2007 includes a $3.0 million non-recurring tax benefit related to an increase in the Texas margin tax carryforward. For the three months and nine months ended September 30, 2006, 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 37% for the remainder of 2007.

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          At December 31, 2006, we had regular tax net operating loss (“NOL”) carryovers of $216.4 million and alternative minimum tax (“AMT”) NOL carryovers of $173.4 million that expire between 2012 and 2026. Even with the gain recognized on the sale of our Gulf of Mexico assets, we expect our NOL carryovers to increase in 2007 due to the current deduction of intangible drilling costs for tax purposes. Our deferred tax asset related to regular NOL carryovers at December 31, 2006 was $51.6 million, net of the SFAS No. 123(R) deduction for unrealized excess tax benefits. At December 31, 2006, we had AMT credit carryovers of $777,000 that are not subject to limitation or expiration.
(6) EARNINGS PER COMMON SHARE
          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,  
    2007     2006     2007     2006  
Numerator:
                               
Income from continuing operations
  $ 59,111     $ 65,058     $ 132,665     $ 168,147  
Income (loss) from discontinued operations, net of taxes
    (196 )     (13,728 )     63,593       (9,872 )
 
                       
Net income
  $ 58,915     $ 51,330     $ 196,258     $ 158,275  
 
                       
 
                               
Denominator:
                               
Weighted average shares outstanding
    148,586       138,318       144,705       133,767  
Stock held in the deferred compensation plan and treasury stock
    (1,404 )     (1,335 )     (1,197 )     (1,341 )
 
                       
Weighted average shares, basic
    147,182       136,983       143,508       132,426  
 
                       
 
                               
Effect of dilutive securities:
                               
Weighted average shares outstanding
    148,586       138,318       144,705       133,767  
Employee stock options, SARs and other
    3,883       3,704       3,992       3,699  
Treasury shares
    (78 )           (26 )      
 
                       
Dilutive potential common shares for diluted earnings per share
    152,391       142,022       148,671       137,466  
 
                       
 
                               
Earnings per common share basic and diluted:
                               
Basic – income from continuing operations
  $ 0.40     $ 0.47     $ 0.92     $ 1.27  
           – discontinued operations
          (0.10 )     0.45       (0.07 )
 
                       
           – net income
  $ 0.40     $ 0.37     $ 1.37     $ 1.20  
 
                       
 
Diluted – income from continuing operations
  $ 0.39     $ 0.46     $ 0.89     $ 1.22  
              – discontinued operations
          (0.10 )     0.43       (0.07 )
 
                       
         – net income
  $ 0.39     $ 0.36     $ 1.32     $ 1.15  
 
                       
          Stock appreciation rights for 544,133 and 281,597 shares were outstanding but not included in the computations of diluted net income per share for the three months and the nine months ended September 30, 2007 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. Stock appreciation rights for 48,000 and 18,000 shares were outstanding but not included in the computations of diluted net income per share for the three months and the nine months ended September 30, 2006 because the grant price of the SARs was greater than the average price of the common shares and would be anti-dilutive to the computations.

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(7) SUSPENDED EXPLORATORY WELL COSTS
          The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2007 and the year ended December 31, 2006 (in thousands):
                 
    September 30,     December 31,  
    2007     2006  
Beginning balance at January 1
  $ 9,984     $ 25,340  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    12,861       4,695  
Reclassifications to wells and equipment based on determination of proved reserves
    (3,430 )     (16,710 )
Capitalized exploratory well costs charged to expense
    (8,225 )     (3,341 )
Divested wells
    (1,325 )      
 
           
Balance at end of period
    9,865       9,984  
Less exploratory well costs that have been capitalized for a period of one year or less
    (8,828 )     (4,792 )
 
           
Capitalized exploratory well costs that have been capitalized for a period greater than one year
  $ 1,037     $ 5,192  
 
           
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    2       3  
 
           
          The $9.9 million of capitalized exploratory well costs at September 30, 2007 was incurred in 2007 ($6.9 million) and in 2006 ($3.0 million). As of September 30, 2007, of the $1.0 million of exploratory costs that have been capitalized for more than one year, one of the wells is not operated by us and the other well has been delayed due to rig availability.
(8) INDEBTEDNESS
          We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2007 is shown parenthetically). No interest expense was capitalized during the three months or the nine months ended September 30, 2007 and 2006.
                 
    September 30,     December 31,  
    2007     2006  
Bank debt (6.3%)
  $ 266,000     $ 452,000  
 
               
Subordinated debt:
               
7.375% Senior Subordinated Notes due 2013, net of discount
    197,515       197,262  
6.375% Senior Subordinated Notes due 2015
    150,000       150,000  
7.5% Senior Subordinated Notes due 2016, net of discount
    249,547       249,520  
7.5% Senior Subordinated Notes due 2017
    250,000        
 
           
Total debt
  $ 1,113,062     $ 1,048,782  
 
           
Bank Debt
          In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or 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 a facility amount or the borrowing base. On September 30, 2007, the facility amount was $900.0 million. On October 22, 2007, the borrowing base was redetermined to be $1.5 billion and the maturity date was extended to October 25, 2012. The bank credit facility provides for a borrowing base subject to redeterminations semi —annually each April and October and pursuant to certain unscheduled redeterminations. Redeterminations other than increases require approval of 75% of the lenders, while increases require unanimous approval. Subject to certain conditions, the facility amount may be increased to the borrowing base amount with twenty days notice. At September 30, 2007, the outstanding balance under the bank credit facility was $266.0 million and there was $634.0 million of borrowing capacity available. Borrowing under the bank credit 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

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such date, or (2) the sum of the federal funds effective rate for such date 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 6.5% for the three months ended September 30, 2007 compared to 6.7% for the three months ended September 30, 2006. The weighted average interest rate on the bank credit facility was 6.5% for the nine months ended September 30, 2007 compared to 6.3% for the same period of 2006. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At September 30, 2007, the commitment fee was 0.25% and the interest rate margin was 1.0%. On October 22, 2007, the interest rate on the bank credit facility (including applicable margin) was 6.2%.
Senior Subordinated Notes
          In 2003, we issued $100.0 million principal amount of 7.375% senior subordinated notes due 2013 (“7.375% Notes”). In 2004, we issued an additional $100.0 million of 7.375% Notes; therefore, $200.0 million of the 7.375% Notes is currently outstanding. In 2005, we issued $150.0 million principal amount of 6.375% senior subordinated notes due 2015 (“6.375% Notes”). In May 2006, we issued $150.0 million principal amount of the 7.5% senior subordinated notes due 2016 (“7.5% Notes due 2016”). In August 2006, we issued an additional $100.0 million of the 7.5% Notes due 2016; therefore, $250.0 million of the 7.5% Notes due 2016 is currently outstanding. On September 28, 2007, we issued $250.0 million principal amount of 7.5% senior subordinated notes due 2017 (“7.5% Notes due 2017”). Interest on our senior subordinated notes is payable semi —annually, at varying times, and each of the notes is guaranteed by certain of our subsidiaries.
          We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. We may redeem the 6.375% Notes, in whole or in part, at any time on or after March 15, 2010, at redemption prices from 103.2% of the principal amount as of March 15, 2010 and declining to 100% on March 15, 2013 and thereafter. Prior to March 15, 2008, we may redeem up to 35% of the original aggregate principal amount of the 6.375% Notes at a redemption price of 106.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. We may redeem the 7.5% Notes due 2016, in whole or in part, at any time on or after May 15, 2011 at redemption prices from 103.75% of the principal amount as of May 15, 2011 and declining to 100% on May 15, 2014 and thereafter. Prior to May 15, 2009, we may redeem up to 35% of the original aggregate principal amount of the 7.5% Notes due 2016 at a redemption price of 107.5% of 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 our 7.5% Notes due 2016 remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs within 60 days of the date of closing the equity sale. We may redeem the 7.5% Notes due 2017, in whole or in part, at any time on or after October 1, 2012 at redemption prices from 103.75% of the principal amount as of October 1, 2012 and declining to 100% on October 1, 2015 and thereafter. Prior to October 1, 2010, we may redeem up to 35% of the original aggregate principal amount of the 7.5% Notes due 2017 at a redemption price of 107.5% of 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 our 7.5% Notes due 2017 remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs within 60 days of the date of closing the equity sale.
          If we experience a change of control, there may be a requirement to repurchase all or a portion of the senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the senior subordinated notes.
Subsidiary Guarantors
          Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees of the 7.375% Notes, the 6.375% Notes, the 7.5% Notes due 2016 and the 7.5% Notes due 2017 are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.

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Debt Covenants
          The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at September 30, 2007. Under the bank credit facility, dividends are permitted, subject to the provisions of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income and 66 —2/3% of net cash proceeds from common stock issuances. Approximately $726.4 million was available under the bank credit facility’s restricted payment basket on September 30, 2007. The terms of each of our subordinated notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings and equity issuances since the original issuance of the notes. The 7.5% Notes due 2016 also allows for any cash proceeds received from the sale of oil and gas property purchased in the Stroud acquisition to be added to the restricted payment basket. At September 30, 2007, $900.8 million was available under the restricted payment baskets for each of the 7.375% Notes, 6.375% Notes and the 7.5% Notes due 2017. There was $981.8 million available under the restricted payment basket for the 7.5% Notes due 2016.
(9) ASSET RETIREMENT OBLIGATION
          A reconciliation of our liability for plugging and abandonment costs, including discontinued operations, for the nine months ended September 30, 2007 and 2006 is as follows (in thousands):
                 
    Nine Months Ended  
    September 30,  
    2007     2006  
Beginning of period
  $ 95,588     $ 68,063  
Liabilities incurred
    3,004       3,150  
Acquisitions
    3,091       1,433  
Liabilities settled
    (1,056 )     (2,973 )
Disposition of wells
    (20,850 )      
Accretion expense – continuing operations
    3,843       2,307  
Accretion expense – discontinued operations
    382       1,119  
Change in estimate
    (3,442 )     3,634  
 
           
End of period
  $ 80,560     $ 76,733  
 
           
          Accretion expense is included as a component of depreciation, depletion and amortization.
(10) CAPITAL STOCK
          We have authorized capital stock of 260 million shares, which includes 250 million shares of common stock and 10 million shares of preferred stock. The following is a schedule of changes in the number of common shares issued:
                 
    Nine Months Ended   Year Ended
    September 30, 2007   December 31, 2006
Beginning of period
    138,931,565       129,913,046  
 
               
Equity offering
    8,050,000        
Shares issued for Stroud acquisition
          6,517,498  
Stock options/SARs exercised
    1,544,193       1,956,164  
Restricted stock grants
    394,497       474,609  
Deferred compensation plan
    13,570       12,998  
In lieu of bonuses
    29,483       20,686  
Contributed to 401(k) plan
          36,564  
 
               
 
    10,031,743       9,018,519  
 
               
 
               
End of period
    148,963,308       138,931,565  
 
               

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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 of 2007, we bought in open market purchases, 155,500 shares at an average price of $34.30. We intend to use such treasury shares for our compensation arrangements to reduce dilution to stockholders.
(11) DERIVATIVE ACTIVITIES
     At September 30, 2007, we had open swap contracts covering 73.9 Bcf of gas at prices averaging $8.99 per mcf. We also had collars covering 29.2 Bcf of gas at weighted average floor and cap prices which range from $7.68 to $10.94 per mcf, and 7.0 million barrels of oil at weighted average floor and cap prices that range from $61.11 to $74.99 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, 2007, was a net unrealized pre-tax gain of $68.9 million. These 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 to oil and gas sales in the period the hedged production is sold. Oil and gas sales were increased by realized gains of $4.1 million in the third quarter of 2007 compared to realized losses of $23.0 million in the third quarter of 2006. Oil and gas sales were increased by realized gains of $14.1 million in the first nine months of 2007 compared with realized losses of $79.6 million in the first nine months of 2006. Other revenues in our consolidated statement of operations include ineffective hedging gains on hedges that qualified for hedge accounting of $502,000 in the first nine months of 2007 compared with gains of $3.5 million in the first nine months of 2006.
     In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices. Also, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf Coast production is now being marked to market. These derivatives have been retained to serve as economic hedges for our production even though we can no longer apply hedge accounting.
     The following table sets forth our natural gas and oil derivative volumes by year as of September 30, 2007:
             
            Weighted
Period   Contract Type   Volume Hedged   Average Hedge Price
Natural Gas
           
2007 – 4th quarter
  Swaps   107,500 Mmbtu/day   $9.49
2007 – 4th quarter
  Collars   98,500 Mmbtu/day   $7.12 — $9.93
2008
  Swaps   135,000 Mmbtu/day   $9.11
2008
  Collars   55,000 Mmbtu/day   $7.93 — $11.40
2009
  Swaps   40,000 Mmbtu/day   8.24
 
           
Crude Oil
           
2007 – 4th quarter
  Collars   8,300 bbl/day   $57.69 — $68.98
2008
  Collars   9,000 bbl/day   $59.34 — $75.48
2009
  Collars   8,000 bbl/day   $64.01 — $76.00
     During the third quarter of 2007, in addition to the swaps and collars above, we entered into basis swap agreements which do not qualify as hedges for hedge accounting purposes and are marked to market. The price we receive for our gas production can be less then 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 our basis adjustments. The fair value of the basis swaps was a net realized pre-tax gain of $1.3 million at September 30, 2007.

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     Prior to July 1, 2007, we had been reclassifying the realized gain and loss from non-hedge derivatives into oil and gas sales. Effective July 1, 2007, we have retroactively reclassified the realized gains and losses from non-hedge derivatives to the line derivative fair value income. Thus, all gains and losses realized and unrealized from non-hedge derivatives are now presented as derivative fair value income. The following is a summary of derivative fair value income included in our consolidated statements of operations (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
Change in unrealized mark-to-market on oil and gas derivative contracts not designated as hedges
  $ 5,618     $ 54,950     $ (40,171 )   $ 83,734  
Cash receipts realized on settlements of non-hedge contracts — gas(a)
    19,417       10,356       50,818       36,180  
Cash payments realized on settlements of non-hedge contracts — oil(a)
    (33 )           (29 )      
 
                       
Derivative fair value income
  $ 25,002     $ 65,306     $ 10,618     $ 119,914  
 
                       
(a)   These amounts represent the realized gains and losses on settled non-hedge derivative, which prior to settlement have been recognized as unrealized mark-to-market gains and losses within derivative fair value income.
     The combined fair values of derivatives included in the consolidated balance sheets at September 30, 2007 and December 31, 2006 are summarized below. Hedging activities are conducted with major financial and commodities trading institutions which we believe are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. We have master netting agreements with our counterparties. The creditworthiness of the counterparties is subject to continuing review.
                 
    September 30,     December 31,  
    2007     2006  
Derivative assets:
               
Natural gas – swaps
  $ 78,559     $ 121,792  
                        – collars
    17,478       36,973  
                        – basis swaps
    937        
Crude oil – collars
    (14,231 )     (4,109 )
 
           
 
  $ 82,743     $ 154,656  
 
           
Derivative liabilities:
               
Natural gas – swaps
    (810 )     248  
                        – collars
    (1,929 )     (2,337 )
                        – basis swaps
    (316 )      
Crude oil – collars
    15,679       6,976  
 
           
 
  $ 12,624     $ 4,887  
 
           
(12) EMPLOYEE BENEFIT AND EQUITY PLANS
     We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, stock appreciation rights (“SARs”), restricted stock awards, phantom stock rights and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee which is made up of independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. During 2007 and 2006, the only type of award issued under our two active plans has been SARs to reduce the dilutive impact of our equity plans. Information with respect to stock option and SARs activities is summarized below:
                 
            Weighted  
            Average  
    Shares     Exercise Price  
Outstanding on December 31, 2006
    8,852,126     $ 12.76  
Granted
    1,667,143       33.71  
Exercised
    (1,754,643 )     10.74  
Expired/forfeited
    (293,865 )     23.32  
 
           
Outstanding on September 30, 2007
    8,470,761     $ 16.94  
 
           

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     The following table shows information with respect to outstanding stock options and SARs at September 30, 2007:
                                         
    Outstanding     Exercisable  
            Weighted-                      
            Average     Weighted-             Weighted-  
            Remaining     Average             Average  
Range of Exercise Prices   Shares     Contractual Life     Exercise Price     Shares     Exercise Price  
$  1.29 — $  9.99
    2,961,039       2.19     $ 4.71       2,961,039     $ 4.71  
  10.00 —   19.99
    2,425,931       2.64       16.21       1,407,814       15.84  
  20.00 —   29.99
    1,498,823       3.49       24.44       443,390       24.38  
  30.00 —   39.99
    1,580,568       4.48       33.80       44,100       38.02  
  40.00 —   41.01
    4,400       4.81       40.66              
 
                             
Total
    8,470,761       2.98     $ 16.94       4,856,343     $ 10.03  
 
                             
     The weighted average fair value of a SAR to purchase one share of common stock granted during 2007 was $10.64. The fair value of each SAR granted during 2007 was estimated as of the date of grant using the Black-Scholes-Merton option pricing model based on the following weighted average assumptions: risk-free interest rate of 4.74%, dividend yield of 0.36%, expected volatility of 35.66% and an expected life of 3.54 years.
     As of September 30, 2007, the aggregate intrinsic value (the difference in value between exercise and market price) of all awards outstanding was $200.9 million. The aggregate intrinsic value and weighted average remaining contractual life of awards currently exercisable was $148.7 million and 2.48 years, respectively. As of September 30, 2007, the number of fully-vested awards and awards expected to vest was 8.3 million shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $16.65 and 2.95 years, respectively, and the aggregate intrinsic value was $198.8 million. As of September 30, 2007, unrecognized compensation cost related to the awards was $21.2 million, which is expected to be recognized over a weighted average period of 1.08 years. Of the total outstanding awards at September 30, 2007, 4.3 million stock options are outstanding with a weighted-average exercise price of $7.93 and 4.2 million SARs are outstanding with a weighted average grant price of $26.36.
Restricted Stock Grants
     During the first nine months of 2007, 429,100 shares of restricted stock were issued to directors and employees as compensation at an average price of $34.75. The grants to directors are immediately vested while the employee grants have a three-year vesting period. In the first nine months of 2006, we issued 476,200 shares of restricted stock as compensation to directors and employees at an average price of $24.32. 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 $2.3 million in the third quarter of 2007 compared to $1.3 million in the same quarter of the prior year. We recorded compensation expense related to restricted stock grants of $6.4 million in the first nine months of 2007 compared to $2.8 million in the same period of 2006. All restricted shares are granted in lieu of cash awards and are placed in the deferred compensation plan (see below). As of September 30, 2007, unrecognized compensation cost related to these restricted stock awards was $20.8 million, which is expected to be recognized over the next 3 years.
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 invests such amounts in Range common stock or makes 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 held in the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability and the carrying value of the deferred compensation liability 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. The deferred compensation liability on our balance sheet reflects the market value of the securities held in the Rabbi Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in other comprehensive income (“OCI”), while changes in the market value of the Range common stock held in the Rabbi Trust are charged or credited to deferred compensation plan expense each quarter. We recorded non-cash mark-to-market expense related to our deferred

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compensation plan of $7.8 million in the third quarter of 2007 compared to income of $2.6 million in the third quarter of 2006. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $28.3 million in the first nine months of 2007 compared to income of $348,000 in the first nine months of 2006.
(13) SUPPLEMENTAL CASH FLOW INFORMATION
                 
    Nine Months Ended
    September 30,
    2007   2006
    (in thousands)
Non-cash investing and financing activities included:
               
Common stock issued under compensation arrangements
  $ 7,660     $ 3,679  
Asset retirement costs capitalized
    (438 )     6,765  
Common stock issued for Stroud purchase
          177,641  
Stock options assumed in Stroud acquisition
          9,478  
 
               
Net cash provided from operating activities included:
               
Income taxes paid
  $ 144     $ 86  
Interest paid
    56,657       39,168  
(14) COMMITMENTS AND CONTINGENCIES
     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.
(15) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (a)
                 
    September 30,     December 31,  
    2007     2006  
    (in thousands)  
Oil and gas properties:
               
Properties subject to depletion
  $ 4,021,173     $ 3,132,830  
Unproved properties
    265,006       226,263  
 
           
Total
    4,286,179       3,359,093  
Accumulated depreciation, depletion and amortization
    (924,155 )     (751,005 )
 
           
Net capitalized costs
  $ 3,362,024     $ 2,608,088  
 
           
 
(a)   Includes capitalized asset retirement costs and associated accumulated amortization.

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(16) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT (a)
                 
    Nine Months        
    Ended     Year Ended  
    September 30,     December 31,  
    2007     2006  
    (in thousands)  
Acquisitions:
               
Unproved leasehold
  $ 4,552     $ 132,821  
Proved oil and gas properties
    246,264       209,262  
Purchase price adjustment (b)
          147,062  
Asset retirement obligation
    3,091       896  
 
               
Acreage purchases
    59,477       79,762  
 
               
Development
    549,786       464,586  
 
Exploration (c)
    66,402       70,870  
 
               
Gas gathering facilities
    13,808       19,690  
 
           
Subtotal
    943,380       1,124,949  
 
Asset retirement obligation
    (438 )     25,821  
 
           
Total costs incurred (d)
  $ 942,942     $ 1,150,770  
 
           
 
(a)   Includes costs incurred whether capitalized or expensed.
 
(b)   Represents non-cash gross up to account for difference in book and tax basis.
 
(c)   Includes $29.7 million of exploration costs expensed in the nine months ended September 30, 2007 and $45.3 million of exploration costs expensed in the year ended December 31, 2006. Exploration expense includes $2.6 million of stock-based compensation in the nine months ended September 30, 2007 and $3.1 million of stock-based compensation in the year ended December 31, 2006.
 
(d)   The year ended December 31, 2006, includes $21.5 million related to our divested Gulf of Mexico properties.
(17) NEW ACCOUNTING STANDARD
     In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes,” and seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes. In addition, FIN 48 provides guidance on de-recognition, classification, interest and penalties, and accounting in interim periods and requires expanded disclosure with respect to the uncertainty in income taxes. We adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect as a result of applying FIN 48. No adjustment was made to our opening balance of retained earnings. We have approximately $600,000 of unrecognized tax benefits recorded as of the date of adoption.
     We file consolidated tax returns in the United States federal jurisdiction and separate income tax returns in many state jurisdictions. We are subject to U.S. Federal income tax examinations for years after 2002 and we are subject to various state tax examinations for years after 2001.
     Our continuing practice is to recognize interest related to income tax expense in interest expense, and penalties in general and administrative expense. We do not have any accrued interest or penalties as of September 30, 2007.
(18) ACCOUNTING STANDARDS NOT YET ADOPTED
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures related to the use of fair value measures in financial statements. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the implementation of SFAS 157 to have a material impact on our results of operations or financial condition.

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     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. This statement allows entities to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the 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 2006 Annual Report on Form 10-K, our Form 8-K filed on June 19, 2007 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. For additional risk factors affecting our business, see the information in Item 1A in our 2006 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate 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, 2006.
Results of Continuing Operations
Volume data
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2007   2006   2007   2006
Production:
                               
Crude oil (bbls)
    839,863       768,832       2,559,992       2,264,827  
NGLs (bbls)
    284,088       277,161       837,625       831,814  
Natural gas (mcf)
    23,261,704       18,889,135       64,469,734       51,157,365  
Total (mcfe) (a)
    30,005,410       25,165,093       84,855,436       69,737,211  
 
                               
Average daily production:
                               
Crude oil (bbls)
    9,129       8,357       9,377       8,296  
NGLs (bbls)
    3,088       3,013       3,068       3,047  
Natural gas (mcf)
    252,845       205,317       236,153       187,390  
Total (mcfe) (a)
    326,146       273,534       310,826       255,448  
 
                               
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcfe.
Overview
     Total revenues increased 10% for the third quarter of 2007 over the same period of 2006. This increase is due to higher production and realized prices. These increases were partially offset by a lower gain from derivative fair value income. For the third quarter of 2007, production increased 19% due to the continued success of our drilling program and acquisitions. Realized oil and gas prices were 20% higher in the third quarter of 2007 compared to the same period of 2006. Our hedges increased oil and gas sales by $4.1 million in the third quarter of 2007 compared to a decrease of $23.0 million in the same period of 2006.
     Higher production volumes and higher realized oil and gas prices have improved our profit margins. However, Range and the oil and gas industry as a whole continued to experience higher operating costs due to heightened competition for qualified employees, goods and services. On a unit cost basis, our direct operating costs increased $0.04 per mcfe, a 4% increase from the third quarter of 2006 to the third quarter of 2007. It is anticipated that service and personnel costs will remain high as long as oil and gas industry fundamentals remain favorable.

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     In the first quarter of 2007, we sold our Gulf of Mexico assets and our Austin Chalk properties that were purchased as part of our Stroud acquisition. These operations are shown in discontinued operations for all periods presented.
Comparison of Quarter Ended September 30, 2007 and 2006
     Oil and gas sales and average price calculations for the three months ended September 30, 2007 and 2006 (in thousands) are summarized in the following tables:
                                 
    Three Months Ended September 30,  
    2007     2006     Change     %  
Oil and Gas Sales:
                               
 
                               
Oil wellhead
  $ 59,218     $ 49,611     $ 9,607       19 %
Oil hedges realized
    (5,120 )     (13,993 )     8,873       63 %
 
                         
Total oil revenue
  $ 54,098     $ 35,618     $ 18,480       52 %
 
                         
 
                               
Gas wellhead
  $ 138,832     $ 115,534     $ 23,298       20 %
Gas hedges realized
    9,235       (9,040 )     18,275       202 %
 
                         
Total gas revenue
  $ 148,067     $ 106,494     $ 41,573       39 %
 
                         
 
                               
NGL revenue
  $ 12,259     $ 10,942     $ 1,317       12 %
 
                         
 
                               
Combined wellhead
  $ 210,309     $ 176,087     $ 34,222       19 %
Combined hedges realized
    4,115       (23,033 )     27,148       118 %
 
                         
Total oil and gas sales
  $ 214,424     $ 153,054     $ 61,370       40 %
 
                         
 
                               
Components of Derivative Fair Value Income:
                               
 
                               
Change in unrealized mark-to-market on oil and gas derivative contracts not designated as hedges(a)
  $ 5,618     $ 54,950     $ (49,332 )     90 %
Cash receipts realized on settlements of non-hedge contracts — gas(d)
    19,417       10,356       9,061       87 %
Cash payments realized on settlements of non-hedge contracts — oil(d)
    (33 )           (33 )      
 
                         
Derivative fair value income
  $ 25,002     $ 65,306     $ (40,304 )     62 %
 
                         
 
                               
Average Sales Price Calculation:
                               
 
                               
Average sales prices (wellhead):
                               
Crude oil (per bbl)
  $ 70.51     $ 64.53     $ 5.98       9 %
NGLs (per bbl)
  $ 43.15     $ 39.48     $ 3.67       9 %
Natural gas (per mcf)
  $ 5.97     $ 6.12     $ (0.15 )     2 %
Total (per mcfe) (b)
  $ 7.01     $ 7.00     $ 0.01        
 
                               
Average sales prices (including hedges):
                               
Crude oil (per bbl)
  $ 64.41     $ 46.33     $ 18.08       39 %
NGLs (per bbl)
  $ 43.15     $ 39.48     $ 3.67       9 %
Natural gas (per mcf)
  $ 6.37     $ 5.64     $ 0.73       13 %
Total (per mcfe) (b)
  $ 7.15     $ 6.08     $ 1.07       18 %
 
                               
Average sales prices (including all derivative settlements):
                               
Crude oil (per bbl)
  $ 64.37     $ 46.33     $ 18.04       39 %
NGLs (per bbl)
  $ 43.15     $ 39.48     $ 3.67       9 %
Natural gas (per mcf)
  $ 7.20     $ 6.19     $ 1.01       17 %
Total (per mcfe) (b)
  $ 7.79     $ 6.49     $ 1.30       20 %
 
                               
Average NYMEX prices(c)
                               
Oil (per bbl)
  $ 75.38     $ 70.48     $ 4.90       7 %
Natural gas (per mcf)
  $ 6.13     $ 6.53     $ (0.40 )     6 %
 
(a)   These amounts are unrealized and are not included in average sales price calculations.
(b)   Oil and NGLs are converted at the rate of one barrel equals six mcfe.
(c)   Based on average of bid week prompt month prices.
(d)   These amounts represent the realized gains and losses on settled non-hedge derivative, which prior to settlement have been recognized as unrealized mark-to-market gains and losses within derivative fair value income.
     The average sales price (including all derivative settlements) received for oil, gas and NGLs during the third quarter of 2007 was $7.79 per mcfe, up 20% or $1.30 per mcfe from the same quarter of the prior year. The average price received in the third quarter for oil increased 39% to $64.37 per barrel and increased 17% to $7.20 per mcf for gas from the same period of 2006. Our derivative program increased realized prices $0.78 per mcfe in the third quarter of 2007 versus a decrease of $0.51 per mcfe in the same period of 2006.
     Production volumes increased 19% from the third quarter of 2006 due to continued drilling success and acquisitions partially offset by natural decline. Production for the third quarter was 326.1 Mmcfe per day of which 60% was attributable to the Southwestern division, 38% to the Appalachian division and 2% to the Gulf Coast division.

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     Derivative fair value income includes a gain of $25.0 million in 2007 compared to a gain of $65.3 million in the same period of 2006. Beginning in the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices. Also, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, the portion of our derivatives which were designated to our Gulf of Mexico production is now being marked to market. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from non-hedge derivatives are included in total revenues and are not included in other comprehensive income. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Because gas prices decreased in the third quarter, our derivatives became comparatively more valuable. However, we expect these gains will be offset by lower wellhead revenues in the future. Beginning in the third quarter of 2007, we have also entered into basis swap agreements which do not qualify as hedges for hedge accounting purposes and are also marked to market.
     Transportation and gathering revenue of $508,000 decreased $507,000 from 2006. This decrease is primarily due to lower processing margins and lower transmission revenues.
     Other revenue increased in 2007 to $2.4 million from $250,000 in 2006. The 2007 period includes $28,000 of ineffective hedging losses, income from equity method investments of $483,000 and $2.2 million of proceeds received from insurance settlements. Other revenue for 2006 includes $184,000 of ineffective hedging gains. The ineffective hedging gains are related to those derivatives that qualified for hedge accounting.
     Our unit 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 ended September 30, 2007 and 2006:
                                 
Expenses per mcfe   2007   2006   Change   %
Direct operating expense (excluding $0.01 per mcfe stock-based compensation in 2007 and $0.02 per mcfe in 2006)
  $ 0.92     $ 0.87     $ 0.05       6 %
Production and ad valorem tax expense
    0.38       0.39       (0.01 )     3 %
General and administrative expense (excluding stock-based compensation of $0.16 per mcfe in 2007 and $0.16 per mcfe in 2006)
    0.44       0.33       0.11       33 %
Interest expense
    0.66       0.65       0.01       2 %
Depletion, depreciation and amortization expense
    1.90       1.61       0.29       18 %
     Direct operating expense (excluding stock-based compensation) increased $5.6 million in the third quarter of 2007 to $27.5 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $1.9 million ($0.06 per mcfe) of workover costs in 2007 versus $712,000 ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.05 from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.01 per mcfe) and higher workover costs ($0.03 per mcfe).
     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $1.4 million or 15% 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 decreased to $0.38 in 2007 from $0.39 in the same period of 2006.
     General and administrative expense (excluding stock-based compensation) for the third quarter of 2007 increased $5.1 million to $13.3 million from 2006 primarily due to higher salaries and benefits ($3.1 million), higher office rent and general office expense ($690,000) and higher professional and accounting fees ($554,000). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.33 in the third quarter of 2006 to $0.44 in the third quarter of 2007.
     Interest expense for the third quarter of 2007 increased $3.5 million to $19.9 million due to higher debt balances and the refinancing of floating bank debt to higher fixed rate debt. In 2006, we issued $250.0 million of 7.5% Notes due 2016 which added $896,000 of interest costs in the third quarter of 2007. In September 2007, we issued $250.0 million of 7.5% Notes due 2017 which added $156,000 of interest costs in the third quarter of 2007. The proceeds from the issuance of both of the 7.5% subordinated notes were used to retire lower floating rate bank debt and we issued the longer term, fixed rate debt to better match the maturities of our debt with the life of our properties. Average debt outstanding on the bank credit facility for the third quarter of 2007 was $492.6 million compared to $412.9 million for the third quarter of 2006 and the average interest rates were 6.5% in the third quarter of 2007 compared to 6.7% in the same quarter of the prior year.

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     Depletion, depreciation and amortization (“DD&A”) increased $16.4 million or 40% to $57.0 million in the third quarter of 2007 with a 19% increase in production, an 18% increase in depletion rates and a $1.7 million unproved acreage impairment in our Gulf Coast business unit. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs, the mix of our production and a $0.06 per mcfe unproved acreage impairment. On a per mcfe basis, DD&A increased from $1.61 in the third quarter of 2006 to $1.90 in the third quarter of 2007.
     Costs and expenses also include stock-based compensation, exploration expense and non-cash deferred compensation plan expenses that generally do not trend with production. In 2006 and 2007, stock-based compensation represents the amortization of restricted stock grants and other stock-based compensation under SFAS No. 123(R). In 2007, stock-based compensation is a component of direct operating expense ($485,000), exploration expense ($931,000), general and administrative expense ($4.7 million) and a $103,000 reduction of net gas transportation revenues for a total of $6.2 million. In 2006, stock-based compensation is a component of direct operating expense ($378,000), exploration expense ($757,000), general and administrative expense ($3.9 million) and an $86,000 reduction of net gas transportation revenues for a total of $5.1 million.
     Exploration expense for the third quarter of 2007 decreased $10.3 million to $6.2 million due to lower dry hole and seismic costs. The following table details our exploration-related expenses for the three months ended September 30, 2007 and 2006 (in thousands):
                                 
Exploration expenses   2007     2006     Change     %  
Dry hole expense
  $ 173     $ 5,564     $ (5,391 )     97 %
Seismic
    1,924       7,248       (5,324 )     73 %
Personnel expense
    2,216       1,761       455       26 %
Stock-based compensation expense
    930       757       173       23 %
Delay rentals and other
    990       1,178       (188 )     16 %
 
                         
Total exploration expense
  $ 6,233     $ 16,508     $ (10,275 )     62 %
 
                         
     Deferred compensation plan expense for the third quarter of 2007 increased $10.4 million to $7.8 million from the same period of 2006 due to an increase in our stock price. Our stock price increased from $37.41 at June 30, 2007 to $40.66 at September 30, 2007. This non-cash category reflects increases or decreases in value of our common stock and other investments held in our non-qualified deferred compensation plans.
     Income tax expense for 2007 decreased to $34.9 million reflecting an 11% decrease in income from continuing operations before taxes compared to the same period of 2006. The third quarter of 2007 provides for tax expense at an effective rate of approximately 37% compared to 38% in the same period of 2006. Current income tax expense of $133,000 represents state income tax of $283,000 offset by a reduction of federal tax expense of $150,000. See also Note 5 to our consolidated financial statements.
     Discontinued operations include the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. The third quarter of 2007 and 2006 provide for tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidated financial statements.

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Comparison of Nine Months Ended September 30, 2007 and 2006
     Oil and gas sales and average price calculations for the nine months ended September 30, 2007 and 2006 (in thousands) are summarized in the following tables:
                                 
    Nine Months Ended September 30,  
    2007     2006     Change     %  
Oil and Gas Sales:
                               
 
                               
Oil wellhead
  $ 161,019     $ 143,213     $ 17,806       12 %
Oil hedges realized
    (7,068 )     (37,239 )     30,171       81 %
 
                       
Total oil revenue
  $ 153,951     $ 105,974     $ 47,977       45 %
 
                       
 
                               
Gas wellhead
  $ 414,758     $ 350,489     $ 64,269       18 %
Gas hedges realized
    21,136       (42,332 )     63,468       150 %
 
                       
Total gas revenue
  $ 435,894     $ 308,157     $ 127,737       41 %
 
                       
 
                               
NGL revenue
  $ 31,791     $ 29,012     $ 2,779       10 %
 
                       
 
                               
Combined wellhead
  $ 607,568     $ 522,714     $ 84,854       16 %
Combined hedges realized
    14,068       (79,571 )     93,639       118 %
 
                       
Total oil and gas sales
  $ 621,636     $ 443,143     $ 178,493       40 %
 
                       
 
                               
Components of Derivative Fair Value Income:
                               
 
                               
Change in unrealized mark-to-market on oil and gas derivative contracts not designated as hedges(a)
  $ (40,171 )   $ 83,734     $ (123,905 )     148 %
Cash receipts realized on settlements of non-hedge contracts — gas(d)
    50,818       36,180       14,638       40 %
Cash payments realized on settlements of non-hedge contracts — oil(d)
    (29 )           (29 )      
 
                       
Derivative fair value income
  $ 10,618     $ 119,914     $ (109,296 )     91 %
 
                       
 
                               
Average Sales Price Calculation:
                               
 
                               
Average sales prices (wellhead):
                               
Crude oil (per bbl)
  $ 62.90     $ 63.23     $ (0.33 )     1 %
NGLs (per bbl)
  $ 37.95     $ 34.88     $ 3.07       9 %
Natural gas (per mcf)
  $ 6.43     $ 6.95     $ (0.52 )     7 %
Total (per mcfe) (b)
  $ 7.16     $ 7.50     $ (0.34 )     5 %
 
                               
Average sales prices (including hedges)
                               
Crude oil (per bbl)
  $ 60.14     $ 46.79     $ 13.35       29 %
NGLs (per bbl)
  $ 37.95     $ 34.88     $ 3.07       9 %
Natural gas (per mcf)
  $ 6.76     $ 6.02     $ 0.74       12 %
Total (per mcfe) (b)
  $ 7.33     $ 6.35     $ 0.98       15 %
 
                               
Average sales prices (including all derivative settlements):
                               
Crude oil (per bbl)
  $ 60.13     $ 46.79     $ 13.34       29 %
NGLs (per bbl)
  $ 37.95     $ 34.88     $ 3.07       9 %
Natural gas (per mcf)
  $ 7.55     $ 6.73     $ 0.82       12 %
Total (per mcfe) (b)
  $ 7.92     $ 6.87     $ 1.05       15 %
 
                               
Average NYMEX prices(c)
                               
Oil (per bbl)
  $ 66.23     $ 68.22     $ (1.99 )     3 %
Natural gas (per mcf)
  $ 6.88     $ 7.47     $ (0.59 )     8 %
 
(a)   These amounts are unrealized and are not included in average sales price calculations.
(b)   Oil and NGLs are converted at the rate of one barrel equals six mcfe.
(c)   Based on average bid week prompt month prices.
(d)   These amounts represent the realized gains and losses on settled non-hedge derivative, which prior to settlement have been recognized as unrealized mark-to-market gains and losses within derivative fair value income.
     The average sales price (including all derivative settlements) received for oil, gas and NGLs during the first nine months of 2007 was $7.92 per mcfe, up 15% or $1.05 per mcfe from the same period of the prior year. The average price received in the first nine months for oil increased 29% to $60.13 per barrel and increased 12% to $7.55 per mcf for gas from the same period of 2006. Our derivative program increased realized prices $0.76 per mcfe in the first nine months of 2007 versus a decrease of $0.63 per mcfe in the same period of 2006.
     Production volumes increased 22% from the first nine months of 2006 primarily due to continued drilling success and acquisitions partially offset by natural decline. Production for the first nine months was 310.8 Mmcfe per day of which 61% was attributable to the Southwestern division, 37% to the Appalachian division and 2% to the Gulf Coast division.
     Derivative fair value income includes a gain of $10.6 million in 2007 compared to a gain of $119.9 million in the same period of 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices. Also, as a result of the

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sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf of Mexico production is now being marked to market. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from non-hedge derivatives are not included in other comprehensive income. Because gas prices decreased in the first nine months, our derivatives became comparatively more valuable. However, we expect these gains will be offset by lower wellhead revenues in the future. Beginning in the third quarter of 2007, we also have entered into basis swap agreements which do not qualify as hedges for hedge accounting purposes and are marked to market.
     Other revenue increased in 2007 to $5.3 million from $3.3 million in 2006. The 2007 period includes insurance proceeds of $2.8 million, income from equity method investments of $1.3 million and $502,000 of ineffective hedging gains. Other revenue for 2006 includes $3.5 million of ineffective hedging gains. The ineffective hedging gains are related to those derivatives that qualified for hedge accounting.
     Our unit 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 nine months ended September 30, 2007 and 2006:
                                 
Expenses per mcfe   2007   2006   Change   %
Direct operating expense (excluding $0.02 per mcfe stock-based compensation in 2007 and $0.01 per mcfe in 2006)
  $ 0.91     $ 0.81     $ 0.10       12 %
Production and ad valorem tax expense
    0.39       0.40       (0.01 )     3 %
General and administrative expense (excluding stock-based compensation of $0.16 per mcfe in 2007 and $0.14 per mcfe in 2006)
    0.43       0.37       0.06       16 %
Interest expense
    0.66       0.54       0.12       22 %
Depletion, depreciation and amortization expense
    1.84       1.53       0.31       20 %
     Direct operating expense (excluding stock-based compensation) increased $20.5 million in the first nine months of 2007 to $76.9 million due to higher oilfield service costs, higher volumes and our acquisitions. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $5.2 million ($0.06 per mcfe) of workover costs in 2007 versus $2.1 million ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.10 from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.03 per mcfe), higher well service costs ($0.04 per mcfe) and higher workover costs ($0.03 per mcfe).
     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $5.0 million or 18% from the same period of the prior year due to higher volumes offset by lower prices and assessed values. On a per mcfe basis, production and ad valorem taxes decreased to $0.39 in 2007 from $0.40 in the same period of 2006.
     General and administrative expense (excluding stock-based compensation) for the first nine months of 2007 increased $11.2 million to $36.9 million primarily due to higher salaries and benefits ($7.7 million), higher office rent and general office expense ($1.5 million) and higher professional and accounting fees ($1.2 million). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.37 in the first nine months of 2006 to $0.43 in the first nine months of 2007.
     Interest expense for the first nine months of 2007 increased $18.1 million to $56.4 million due to rising interest rates, higher average debt balances and the refinancing of floating bank debt to higher fixed rate debt. In 2006, we issued $250.0 million of 7.5% Notes due 2016 which added $9.1 million of interest costs in the first nine months of 2007. In September 2007, we issued $250.0 million of 7.5% Notes due 2017 which added $156,000 of interest costs in the first nine months of 2007. The proceeds from the issuance of both the 7.5% senior subordinated notes were used to retire lower floating rate bank debt and we issued the longer term, fixed rate debt to better match the maturities of our debt with the life of our properties. Average debt outstanding on the bank credit facility for the first nine months of 2007 was $452.5 million compared to $318.7 million for the first nine months of 2006 and the average interest rates were 6.5% in the first nine months of 2007 compared to 6.3% in the same period of the prior year.
     Depletion, depreciation and amortization (“DD&A”) increased $49.5 million or 47% to $155.8 million in the first nine months of 2007 with a 22% increase in production, a 20% increase in depletion rates and a $1.7 million acreage impairment. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs, the mix of our production and a $0.02 per mcfe unproved acreage impairment. On a per mcfe basis, DD&A increased from $1.53 in the first nine months of 2006 to $1.84 in the first nine months of 2007.

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     Costs and expenses also include stock-based compensation, exploration expense and non-cash deferred compensation plan expenses that generally do not trend with production. In 2006 and 2007, stock-based compensation represents the amortization of restricted stock grants and other stock-based compensation under SFAS No. 123(R). In 2007, stock-based compensation is a component of direct operating expense ($1.4 million), exploration expense ($2.6 million), general and administrative expense ($13.7 million) and a $297,000 reduction of net gas transportation revenues for a total of $18.0 million. In 2006, stock-based compensation is a component of direct operating expense ($1.0 million), exploration expense ($2.2 million), general and administrative expense ($10.3 million) and a $237,000 reduction of net gas transportation revenues for a total of $13.8 million.
     Exploration expense for the first nine months of 2007 decreased $3.5 million to $29.7 million due to lower seismic costs partially offset by higher personnel costs. The following table details our exploration-related expenses for the first nine months ended September 30, 2007 and 2006 (in thousands):
                                 
Exploration expenses   2007     2006     Change     %  
Dry hole expense
  $ 9,071     $ 9,293     $ (222 )     2 %
Seismic
    8,260       14,191       (5,931 )     42 %
Personnel expense
    6,543       4,925       1,618       33 %
Stock-based compensation expense
    2,589       2,196       393       18 %
Delay rentals and other
    3,205       2,588       617       24 %
 
                         
Total exploration expense
  $ 29,668     $ 33,193     $ (3,525 )     11 %
 
                         
     Deferred compensation plan expense for the first nine months of 2007 increased $28.7 million from the same period of 2006 due to an increase in our stock price. Our stock price increased from $27.46 at December 31, 2006 to $40.66 at September 30, 2007. This non-cash category reflects increases or decreases in value of our common stock and other investments held in our non-qualified deferred compensation plans.
     Income tax expense for 2007 decreased to $74.1 million reflecting the 23% decrease in income from continuing operations before taxes compared to the same period of 2006. The first nine months of 2007 provides for tax expense at an effective rate of approximately 36% compared to 38% in the same period of 2006. The nine months ended September 30, 2007 includes a non-recurring $3.0 million tax benefit related to an increase in the Texas margin tax credit carryover. Current income tax of $416,000 represents state income tax of $545,000 offset by a reduction of federal tax expense of $129,000. See also Note 5 to our consolidated financial statements.
     Discontinued operations include the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. The first nine months of 2007 and 2006 provide for tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidated financial statements.
Liquidity and Capital Resources
     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a committed bank credit facility and access to both the debt and equity capital markets. During the nine months ended September 30, 2007, net cash provided from continuing operations of $445.5 million, proceeds from our April 2007 common stock offering of $280.4 million and proceeds from the sale of assets of $234.3 million were used to fund $1.0 billion of capital expenditures (including acquisitions and equity investments). At September 30, 2007, we had $187,000 in cash and total assets of $3.8 billion. Our debt to capitalization ratio was 39.4% at September 30, 2007 compared to 45.5% at December 31, 2006. As of September 30, 2007 and December 31, 2006, our total capitalization was as follows (in thousands):
                 
    September 30,     December 31,  
    2007     2006  
Bank debt
  $ 266,000     $ 452,000  
Senior subordinated notes
    847,062       596,782  
 
           
Total debt
    1,113,062       1,048,782  
Stockholders’ equity
    1,708,812       1,256,161  
 
           
Total capitalization
  $ 2,821,874     $ 2,304,943  
 
           

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     Long-term debt at September 30, 2007 totaled $1.1 billion, including $266.0 million of bank credit facility debt and $847.1 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at September 30, 2007 was $634.0 million. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities and unused committed borrowing capacity under the bank credit facility combined with our oil and gas price hedges currently in place 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 on prospective projects that we believe are necessary to offset inherent declines in production and proven reserves.
Bank Debt and Senior Subordinated Notes
     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at September 30, 2007. Under the bank credit facility, common and preferred dividends are permitted, subject to the terms of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances occurring since December 31, 2001. Approximately $726.4 million was available under the bank credit facility’s restricted payment basket on September 30, 2007. The terms of our senior subordinated notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings since the issuance of the notes and 100% of net cash proceeds from common stock issuances. The 7.5% Notes due 2016 also allow for any cash proceeds received from the sale of oil and gas properties purchased in the Stroud acquisition to be added to the restricted payment basket. Approximately $900.8 million was available under the restricted payment basket for each of the 7.375% Notes, 6.375% Notes and the 7.5% Notes due 2017 on September 30, 2007. There was $981.8 million available under the restricted payment basket for 7.5% Notes due 2016 at September 30, 2007.
     On September 28, 2007, we issued $250.0 million principal amount of 7.5% senior subordinated notes due 2017. The proceeds from the issuance of these notes were used to pay down our bank credit facility. We maintain a $900.0 million revolving bank credit facility commitment. The facility is secured by substantially all our assets. Availability under the facility is subject to a borrowing base set by the banks semi-annually and in certain other circumstances more frequently. The borrowing base is dependent on a number of factors, primarily the lenders’ assessment of future cash flows. Redeterminations other than increases require the approval of 75% of the lenders, while increases require unanimous approval. On October 22, 2007, the borrowing base was redetermined to be $1.5 billion and the maturity date was extended to October 25, 2012. Credit availability is equal to the lesser of the facility amount or the borrowing base, resulting in credit availability of $589.0 million on October 22, 2007.
Cash Flow
     Our principal sources of cash are operating cash flow and bank borrowings and at times, the sale of assets and the issuance of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices. As of September 30, 2007, we have entered into derivative agreements covering 23.5 Bcfe, 89.3 Bcfe and 32.1 Bcfe for 2007, 2008 and 2009, which represents 80%, 72% and 24% of our forecasted production, respectively. Net cash provided from continuing operations for the nine months ended September 30, 2007 was $445.5 million compared to $319.7 million in the nine months ended September 30, 2006. Cash flow from operations was higher than the prior year due to higher volumes and realized prices partially offset by higher operating costs. Net cash used in investing for the nine months ended September 30, 2007 was $798.3 million compared to $714.6 million in the same period of 2006. The 2007 period includes $601.0 million of additions to oil and gas properties and $309.7 million of acquisitions, partially offset by proceeds of $234.3 million from asset sales. The 2006 period included $328.4 million of additions to oil and gas properties and $336.7 million of acquisitions. Net cash provided from financing for the nine months ended September 30, 2007 was $340.4 million compared to $364.0 million in the first nine months of 2006. During the first nine months of 2007 total debt increased $64.3 million.
Dividends
     On September 1, 2007, the Board of Directors declared a dividend of three cents per share ($4.5 million) on our common stock, payable on September 28, 2007 to stockholders of record at the close of business on September 17, 2007.

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Capital Requirements and Contractual Cash Obligations
     The 2007 capital budget is currently set at $890.0 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow and asset sales. For the nine months ended September 30, 2007, $616.2 million of development and exploration spending was funded with internal cash flow and proceeds from the sale of assets.
     There have been no significant changes to our contractual obligations subsequent to December 31, 2006. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2006.
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 the liquidity or consolidated financial position of Range.
Hedging – Oil and Gas Prices
     We enter into derivative agreements to reduce the impact of oil and gas price volatility on our operations. At September 30, 2007, swaps were in place covering 73.9 Bcf of gas at prices averaging $8.99 per mcf. We also had collars covering 29.2 Bcf of gas at weighted average floor and cap prices which range from $7.68 to $10.94 per mcf, and 7.0 million barrels of oil at weighted average floor and cap prices that range from $61.11 to $74.99 per barrel. The derivative fair value, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, was a net unrealized pre-tax gain of $68.9 million at September 30, 2007. 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 revenues in the period the hedged production is sold. An ineffective portion (changes in contract prices that do not match changes in the hedge price) of open hedge contracts that qualify for hedge accounting is recognized in earnings quarterly in other revenue.
     At September 30, 2007, the following commodity derivative contracts were outstanding:
             
Period   Contract Type   Volume Hedged   Average Hedge Price
Natural Gas
           
2007 – 4th quarter
  Swaps   107,500 Mmbtu/day   $9.49
2007 – 4th quarter
  Collars   98,500 Mmbtu/day   $7.12 - $9.93
2008
  Swaps   135,000 Mmbtu/day   $9.11
2008
  Collars   55,000 Mmbtu/day   $7.93 - $11.40
2009
  Swaps   40,000 Mmbtu/day   $8.24
 
           
Crude Oil
           
2007 – 4th quarter
  Collars   8,300 bbl/day   $57.69 - $68.98
2008
  Collars   9,000 bbl/day   $59.34 - $75.48
2009
  Collars   8,000 bbl/day   $64.01 - $76.00
     As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting and are marked to market. Also, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of derivatives which were designated to our Gulf Coast production is now being marked to market. As of September 30, 2007 hedges on 63.1 Bcfe no longer qualify or are not designated for hedge accounting.
     During the third quarter of 2007, in addition to the swaps and collars above, we entered into basis swap agreements which 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 $1.3 million at September 30, 2007. All of these situations where we are marking derivatives to market resulted in a gain of $10.6 million in the first nine months of 2007 compared to a gain of $119.9 million in the first nine months of 2006.

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Interest Rates
     At September 30, 2007, we had $1.1 billion of debt outstanding. Of this amount, $850.0 million bore interest at fixed rates averaging 7.3%. Bank debt totaling $266.0 million bears interest at floating rates, which average 6.3% at September 30, 2007. The 30 day LIBOR rate on September 30, 2007 was 5.1%.
Inflation and Changes in Prices
     Our revenues, the value of our assets and 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, the costs to produce our reserves and capital market availability. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During the third quarter of 2007, we received an average of $70.51 per barrel of oil and $5.97 per mcf of gas before derivative contracts compared to $64.53 per barrel of oil and $6.12 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. Commodity prices for oil and gas increased significantly in 2004, 2005 and 2006 and commodity prices for oil continued to increase in 2007. 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 remain high for the remainder of 2007 even in the face of moderating or declining near-term gas prices.
New Accounting Standards
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures related to the use of fair value measures in financial statements. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the implementation of SFAS 157 to have a material impact on our results of operations or financial condition.
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. This statement allows entities to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the 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 US dollar denominated.
     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 hedging 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 establish a minimum floor price and a predetermined ceiling price. Realized gains or losses on derivatives that qualify for hedge accounting are recognized in oil and gas revenue when the associated production occurs. Gains or losses on open contracts are recorded either in current period income or other comprehensive income. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Ineffective gains and losses on those derivatives that qualify for hedge accounting are recognized in earnings in other revenues. We do not enter into derivative instruments for trading purposes. Though not all of our derivatives qualify or are designated as accounting hedges, the purpose of entering into the contracts is to economically hedge oil and gas prices. Those that do not qualify as accounting hedges are marked to market through earnings in the line derivative fair value income.
     As of September 30, 2007, we had gas swaps in place covering 73.9 Bcf of gas. We also had collars covering 29.2 Bcf of gas and 7.0 million barrels of oil. Their fair value, represented by the estimated amount that would be realized upon immediate liquidation, based on contract versus NYMEX prices, approximated a net unrealized pre-tax gain of $68.9 million at that date. These contracts expire monthly through December 2009. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price received by us for the sale of our hedged production and the hedge price, generally closing prices on the NYMEX. Losses or gains due to commodity hedge ineffectiveness on derivatives that qualify for hedge accounting are recognized in earnings in other revenues in our consolidated statement of operations.
     At September 30, 2007, the following commodity derivative contracts were outstanding:
                     
Period   Contract Type   Volume Hedged   Average Hedge Price   Fair Market Value  
                (In thousands)  
Natural Gas
                   
2007 – 4th quarter
  Swaps   107,500 Mmbtu/day   $9.49   $ 24,435  
2007 – 4th quarter
  Collars   98,500 Mmbtu/day   $7.12 - $9.93   $ 5,284  
2008
  Swaps   135,000 Mmbtu/day   $9.11   $ 55,330  
2008
  Collars   55,000 Mmbtu/day   $7.93 - $11.40   $ 14,123  
2009
  Swaps   40,000 Mmbtu/day   $8.24   $ (397 )
 
                   
Crude Oil
                   
2007 – 4th quarter
  Collars   8,300 bbl/day   $57.69 - $68.98   $ (9,073 )
2008
  Collars   9,000 bbl/day   $59.34 - $75.48   $ (15,192 )
2009
  Collars   8,000 bbl/day   $64.01 - $76.00   $ (5,644 )
     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. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the volatility in gas prices and its effect on our basis differentials and are marked to market. Also, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007 a portion of the derivatives designated against our Gulf of Mexico production is now being marked to market. In

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addition, during the third quarter of 2007, we entered into basis swap agreements which do not qualify as hedges for hedge accounting purposes and are marked to market. The price we receive for our gas 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 $1.3 million at September 30, 2007. In all of these situations where we are marking derivative instruments to market resulted in a gain of $10.6 million in the first nine months of 2007 compared to a gain of $119.9 million in the same period of 2006.
     In the first nine months of 2007, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $60.5 million. If oil and gas future prices at September 30, 2007 declined 10%, the unrealized hedging gain at that date would have increased by $87.5 million.
     Interest rate risk. At September 30, 2007, we had $1.1 billion of debt outstanding. Of this amount, $850.0 million bore interest at fixed rates averaging 7.3%. Senior debt totaling $266.0 million bore interest at floating rates averaging 6.3%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $2.7 million.

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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 IA. Risk Factors
     The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the “Risk Factors” section of our 2006 Annual Report on Form 10-K. There have been no material changes from the risk factors and information disclosed in the “Risk Factors” section of our 2006 Annual Report on Form 10-K except that:
    In light of the sale of our Gulf of Mexico properties in March 2007, we deleted the risk factor entitled “A portion of our business is subject to special risks generally related to offshore operations and specifically in the Gulf of Mexico”;
 
    We revised the risk factor set forth below entitled “Hedging transactions may limit our potential gains and involve other risks” by adding a new sentence to the risk factor as follows: “As a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf Coast production is now being marked to market”; and
Hedging transactions may limit our potential gains and involve other risks
     To manage our exposure to price risk, we enter into hedging arrangements with respect to a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if oil and natural gas prices rise above the price established by the hedge.
     In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
    our production is less than expected;
 
    the counterparties to our futures contracts fail to perform under the contracts; or
 
    a sudden, unexpected event materially impacts oil or natural gas prices or the relationship between the hedged price index and the oil and gas sales price.
     In the fourth quarter of 2005, due to the trading volatility of NYMEX gas contracts, we experienced larger than usual differentials between actual prices paid at delivery points and NYMEX based gas hedges. Due to this event, certain of our gas hedges no longer qualify for hedge accounting and are marked to market. As a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf Coast production is now being marked to market. This may result in more volatility in our income in future periods.
    We revised the risk factor set forth below entitled “Our indebtedness could limit our ability to successfully operate our business” to revise the title of the risk factor and to update the capital resource estimates set forth in the risk factor.
Our significant indebtedness could limit our ability to successfully operate our business
     We are leveraged and our exploration and development program will require substantial capital resources estimated to range from $800.0 million to $1.1 billion per year over the next three years, depending on the level of drilling and the expected cost of services. Our existing operations will also require ongoing capital expenditures. In addition, if we decide to pursue additional acquisitions, our capital expenditures will increase both to complete such acquisitions and to explore and develop any newly acquired properties.
     The degree to which we are leveraged could have other important consequences, including the following:
    we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;
 
    a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;
 
    we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;
 
    our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;
 
    the terms of our existing credit arrangements contain numerous financial and other restrictive covenants;
 
    our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
 
    we may have difficulties borrowing money in the future.
     Despite our current levels of indebtedness we still may be able to incur substantially more debt. This could further increase the risks described above.
Item 6. Exhibits
(a) EXHIBITS
     
Exhibit    
Number   Description
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 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)
 
   
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)
 
   
10.3
  Purchase and Sale Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc. and Equitable Production Company (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2007)
 
   
10.4
  Contribution Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc., Equitable Production Company, Equitable Gathering Equity, LLC and Nora Gathering LLC (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2007)
 
   
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

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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   
    Senior Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)   
 
October 24, 2007

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     Exhibit index
     
Exhibit    
Number   Description
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 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)
 
   
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)
 
   
10.3
  Purchase and Sale Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc. and Equitable Production Company (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2007)
 
   
10.4
  Contribution Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc., Equitable Production Company, Equitable Gathering Equity, LLC and Nora Gathering LLC (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2007)
 
   
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