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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, 2006
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.)
     
777 Main Street, Suite 800, 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
138,629,929 Common Shares were outstanding on October 23, 2006.
 
 

 


Table of Contents

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended September 30, 2006
          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
             
        Page
PART I – FINANCIAL INFORMATION        
Item 1.          
        3  
   
 
       
        4  
   
 
       
        5  
   
 
       
        6  
   
 
       
        7  
   
 
       
Item 2.       20  
   
 
       
Item 3.       28  
   
 
       
PART II – OTHER INFORMATION        
   
 
       
Item 6.       31  
 Certification Pursuant to Section 302
 Certification Pursuant to Section 302
 Certification Pursuant to Section 906
 Certification Pursuant to Section 906

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PART I – Financial Information
ITEM 1. – Financial Statements
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
                 
    September 30,     December 31,  
    2006     2005  
Assets
  (Unaudited)        
Current assets
               
Cash and equivalents
  $ 2,251     $ 4,750  
Accounts receivable, less allowance for doubtful accounts of $488 and $624
    121,362       128,532  
Unrealized derivative gain
    52,558       425  
Deferred tax asset
    2,647       61,677  
Inventory and other
    15,493       12,593  
Assets held for sale
    117,275        
 
           
Total current assets
    311,586       207,977  
 
           
 
               
Unrealized derivative gain
    71,850        
Equity method investment
    12,523        
 
               
Oil and gas properties, successful efforts method
    3,461,697       2,548,090  
Accumulated depletion and depreciation
    (915,222 )     (806,908 )
 
           
 
    2,546,475       1,741,182  
 
           
Transportation and field assets
    74,919       65,210  
Accumulated depreciation and amortization
    (31,057 )     (25,966 )
 
           
 
    43,862       39,244  
 
           
Other assets
    64,954       30,582  
 
           
Total assets
  $ 3,051,250     $ 2,018,985  
 
           
 
               
Liabilities
               
Current liabilities
               
Accounts payable
  $ 150,996     $ 119,907  
Asset retirement obligations
    3,796       3,166  
Accrued liabilities
    38,627       28,372  
Accrued interest
    11,417       10,214  
Unrealized derivative loss
    11,172       160,101  
 
           
Total current liabilities
    216,008       321,760  
 
           
 
               
Bank debt
    384,700       269,200  
Subordinated notes
    596,694       346,948  
Deferred tax, net
    469,612       174,817  
Unrealized derivative loss
    4,880       70,948  
Deferred compensation liability
    82,290       73,492  
Asset retirement obligations
    72,937       64,897  
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, 138,546,673 shares issued at September 30, 2006 and 129,913,046 shares issued at December 31, 2005
    1,385       1,299  
Common stock held in treasury – none at September 30, 2006 and 5,826 shares at December 31, 2005
          (81 )
Capital in excess of par value
    1,068,763       845,519  
Retained earnings
    164,054       13,800  
Common stock held by employee benefit trust, 1,881,176 shares at September 30, 2006 and 1,971,605 shares at December 31, 2005, at cost
    (21,939 )     (11,852 )
Deferred compensation
          (4,635 )
Accumulated other comprehensive income (loss)
    11,866       (147,127 )
 
           
Total stockholders’ equity
    1,224,129       696,923  
 
           
Total liabilities and stockholders’ equity
  $ 3,051,250     $ 2,018,985  
 
           
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,  
    2006     2005     2006     2005  
Revenues
                               
Oil and gas sales
  $ 172,647     $ 142,055     $ 506,605     $ 368,193  
Transportation and gathering
    1,034       703       2,009       1,862  
Mark-to-market on oil and gas derivatives
    54,950             83,734        
Other
    249       (968 )     3,253       (621 )
 
                       
Total revenue
    228,880       141,790       595,601       369,434  
 
                       
 
                               
Costs and expenses
                               
Direct operating
    24,784       16,902       64,987       49,129  
Production and ad valorem taxes
    9,985       8,457       28,381       21,246  
Exploration
    16,512       7,725       34,367       20,120  
General and administrative
    12,170       9,019       36,014       21,863  
Non-cash stock compensation
    (2,638 )     17,450       (347 )     26,793  
Interest expense
    16,896       9,910       39,450       28,041  
Depletion, depreciation and amortization
    46,243       32,900       117,643       93,098  
 
                       
Total costs and expenses
    123,952       102,363       320,495       260,290  
 
                       
 
                               
Income from continuing operations before income taxes
    104,928       39,427       275,106       109,144  
 
                               
Income tax
                               
Current
    615       331       1,815       331  
Deferred
    38,899       14,431       101,497       40,484  
 
                       
 
    39,514       14,762       103,312       40,815  
 
                       
 
                               
Income from continuing operations
    65,414       24,665       171,794       68,329  
Discontinued operations, net of income taxes
    (14,084 )           (13,519 )      
 
                       
 
                               
Net income
  $ 51,330     $ 24,665     $ 158,275     $ 68,329  
 
                       
 
                               
Earnings per common share:
                               
Basic — income from continuing operations
  $ 0.48     $ 0.19     $ 1.30     $ 0.56  
 
                       
- discontinued operations
  $ (0.11 )   $     $ (0.10 )   $  
 
                       
- net income
  $ 0.37     $ 0.19     $ 1.20     $ 0.56  
 
                       
 
                               
Diluted — income from continuing operations
  $ 0.46     $ 0.19     $ 1.25     $ 0.54  
 
                       
- discontinued operations
  $ (0.10 )   $     $ (0.10 )   $  
 
                       
- net income
  $ 0.36     $ 0.19     $ 1.15     $ 0.54  
 
                       
 
                               
Dividends per common share
  $ 0.02     $ 0.013     $ 0.06     $ 0.039  
 
                       
See accompanying notes

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
                 
    Nine Months Ended  
    September 30,  
    2006     2005  
Increase (decrease) in cash and equivalents Operating activities:
               
Net income
  $ 158,275     $ 68,329  
Adjustments to reconcile net income to net cash provided from operating activities:
               
Loss from discontinued operations
    13,519        
Loss from equity method investment
    61        
Deferred income tax expense
    101,497       40,484  
Depletion, depreciation and amortization
    117,643       93,098  
Unrealized derivative gains
    (3,178 )     377  
Mark-to-market on oil and gas derivatives
    (83,734 )      
Allowance for bad debts
    33       675  
Exploration dry hole costs
    10,314       2,504  
Amortization of deferred issuance costs and other
    1,221       1,261  
Deferred compensation adjustments
    13,839       30,413  
Loss on sale of assets and other
    976       157  
Changes in working capital, net of amounts from business acquisition:
               
Accounts receivable
    32,497       (16,954 )
Inventory and other
    (1,911 )     (6,879 )
Accounts payable
    (17,800 )     5,535  
Accrued liabilities and other
    (878 )     (2 )
 
           
Net cash provided from continuing operations
    342,374       218,998  
Net cash provided from discontinued operations
    5,766        
 
           
Net cash provided from operating activities
    348,140       218,998  
 
           
 
               
Investing activities:
               
Additions to oil and gas properties
    (339,686 )     (194,128 )
Additions to field service assets
    (10,033 )     (7,183 )
Acquisitions, net of cash acquired
    (336,735 )     (145,341 )
Investing activities of discontinued operations
    (7,306 )      
Investment in equity method affiliate and other assets
    (21,008 )      
Proceeds from disposal of assets and other
    166       5,141  
 
           
Net cash used in investing activities
    (714,602 )     (341,511 )
 
           
 
               
Financing activities:
               
Borrowings on credit facility
    650,500       217,600  
Repayments on credit facility
    (535,000 )     (361,700 )
Other debt repayments
          (16 )
Debt issuance costs
    (5,560 )     (4,118 )
Treasury stock purchases
          (2,808 )
Dividends paid – common stock
    (8,021 )     (4,990 )
– preferred stock
          (2,213 )
Issuance of subordinated notes
    249,500       150,000  
Issuance of common stock
    12,544       113,764  
 
           
Net cash provided from financing activities
    363,963       105,519  
 
           
 
               
Net decrease in cash and equivalents
    (2,499 )     (16,994 )
Cash and equivalents at beginning of period
    4,750       18,382  
 
           
Cash and equivalents at end of period
  $ 2,251     $ 1,388  
 
           
See accompanying notes

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Net income
  $ 51,330     $ 24,665     $ 158,275     $ 68,329  
Net deferred hedge gains (losses), net of tax:
                               
Contract settlements for current period sales reclassified to income
    8,511       26,068       29,351       53,325  
Change in unrealized deferred hedging gains (losses)
    72,692       (169,344 )     129,451       (235,462 )
Change in unrealized gains on securities held by deferred compensation plan, net of taxes
    433       539       191       642  
 
                       
Comprehensive income (loss)
  $ 132,966     $ (118,072 )   $ 317,268     $ (113,166 )
 
                       
See accompanying notes.

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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(1) ORGANIZATION AND NATURE OF BUSINESS
     We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange.
(2) BASIS OF PRESENTATION
     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2005 Annual Report on Form 10-K. 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 (the 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. All common stock shares, treasury stock shares and per-share amounts have been adjusted to reflect the three-for-two stock split effected on December 2, 2005.
     Certain reclassifications of prior year data have been made to conform to 2006 classifications. For the first six months of 2006, non-cash compensation expense recognized as a result of adopting Statement No. 123(R) was recorded in non-cash stock compensation. The nine months ended September 2006 includes a year-to-date reclassification of this expense from non-cash stock compensation into direct operating expense ($645,000), exploration expense ($1.2 million), general and administrative expense ($5.1 million) and a reduction of $145,000 in transportation and gathering revenues which aligns the Statement No. 123(R) expense with the respective employee’s cash compensation. The following table is a summary of this reclassification by quarter (in thousands):
                         
    Three Months     Six Months  
    Ended     Ended  
    March 31,     June 30,     June 30,  
    2006     2006     2006  
Transportation and gathering revenues
  $ 65     $ 80     $ 145  
Direct operating expense
    285       360       645  
Exploration expense
    559       653       1,212  
General and administrative expense
    1,931       3,208       5,139  
 
                 
Statement No. 123(R) expense
  $ 2,840     $ 4,301     $ 7,141  
 
                 
      The 2005 SARs-related expense has also been reclassified to conform to this presentation. The $2.7 million of mark-to-market SARs expense was reclassed to transportation and gathering revenues ($55,000), direct operating expense ($226,000), exploration expense ($551,000) and general and administrative expense ($1.8 million). Unlike the other forms of stock compensation, the deferred compensation plan cost is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories.
(3) ACQUISITIONS AND DISPOSITIONS
     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. We purchased various properties for $707.2 million and $167.3 million during the nine months ended September 30, 2006 and 2005, respectively. The purchases included $649.1 million and $153.0 million for proved oil and gas reserves for the nine months ended September 30, 2006 and 2005, respectively, with the remainder representing unproved acreage.
     Our purchases in 2006 include the acquisition in June of Stroud Energy, Inc., or 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 (including transaction costs) and issued 6.5 million shares of our common stock. The cash portion of the acquisition was funded with borrowings under our bank facility. We also assumed $106.7 million of Stroud’s debt which was retired with borrowings under our bank facility. The fair value of consideration issued was based on the average of our stock price for the five day period before and after May 11, 2006, the date the acquisition was announced.

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     The following table summarizes the estimated fair values of assets acquired and liabilities assumed at closing. We are in the process of finalizing fair value estimates for certain assets and liabilities, particularly pre-acquisition revenues and expenses; thus the allocation of purchase price is preliminary (in thousands):
         
Purchase price:
       
Cash paid (including transaction costs)
  $ 171,480  
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
  $ 465,299  
 
     
 
       
Allocation of purchase price:
       
Working capital deficit
  $ (12,824 )
Other long-term assets
    767  
Other property and equipment
    39  
Oil and gas properties
    506,541  
Assets held for sale
    140,000  
Deferred income taxes
    (166,891 )
Other long-term liabilities
    (900 )
Asset retirement obligations
    (1,433 )
 
     
Total
  $ 465,299  
 
     
     The following unaudited pro forma data include the results of operations as if the Stroud acquisition had been consummated at the beginning of 2005. The pro forma information for 2005 includes two material non-recurring amounts. The three months and the nine months ended September 30, 2005 pro forma information includes an $18.4 million pre-tax stock compensation expense related to restricted and unrestricted shares issued to Stroud management and employees and a pre-tax $6.2 million loss on repurchase of mandatorily redeemable preferred units. The pro forma data is based on historical information and does 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).
                       
      Three Months Ended   Nine Months Ended
      September 30,   September 30,
      2005   2006   2005
Revenues
    $ 139,382     $ 630,421     $ 372,873       
Income from continuing operations
    $ 583     $ 170,690     $ 59,725       
Net income
    $ 3,857     $ 160,942     $ 43,524       
 
                         
Per share data:
                         
Income from continuing operations-basic
    $     $ 1.25     $ 0.29       
Income from continuing operations-diluted
    $     $ 1.21     $ 0.28       
 
                         
Net income-basic
    $ 0.03     $ 1.18     $ 0.34       
Net income-diluted
    $ 0.03     $ 1.14     $ 0.32       

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(4) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
     As part of the Stroud acquisition (see discussion in Note 3), we purchased Austin Chalk properties in Central Texas which we plan to sell. Management has been authorized to sell the properties which are expected to be sold within the next nine months. We believe we have met the criteria of SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” that allow us to classify these assets as held for sale on our balance sheet. We will present the results of operations (revenues less direct expenses, interest, impairment and taxes) as discontinued operations in all future periods. Discontinued operations for the three months and the nine months ended September 30, 2006 are summarized as follows:
                 
    Three Months     June 19, 2006  
    Ended     through  
    September 30,     September 30,  
    2006     2006  
Revenues
  $ 9,721     $ 10,739  
Less:
               
Direct operating and production and ad valorem taxes
    773       894  
General and administrative
    175       175  
Interest expense (1)
    752       752  
Impairment and accretion expense (2)
    30,376       30,376  
 
           
Net loss before income taxes
    (22,355 )     (21,458 )
Income tax benefit
    8,271       7,939  
 
           
Net loss from discontinued operations
  $ (14,084 )   $ (13,519 )
 
           
 
               
Average daily production:
               
Crude oil (bbls)
    97       97  
Natural gas (mcfs)
    16,250       16,448  
Total (per mcfe)
    16,832       17,030  
 
(1)   Interest expense is allocated to discontinued operations based on our ratio of consolidated debt to equity at the time of the acquisition.
 
(2)   Impairment expense includes losses in fair value resulting from lower oil and gas prices and production. Gains for subsequent increases in fair value due to higher oil and gas prices will be recognized to the extent impairment has been previously recognized.
     At the acquisition date, Nymex oil and gas prices were $0.22 per barrel and $0.29 per mcf higher than September 30, 2006. The Company believes that the reduction in oil and gas prices has reduced the fair value of assets being held for sale by $25.0 million. The remainder of the impairment and accretion amount is due to the changes in the discount rate used to estimate fair value and the volumes produced since the acquisition date.
(5) SUSPENDED EXPLORATORY WELL COSTS
     The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2006 and the twelve months ended December 31, 2005 (in thousands):
                 
    September 30,     December 31,  
    2006     2005  
Beginning of period
  $ 25,340     $ 7,332  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    8,350       26,915  
Reclassifications to wells, facilities and equipment based on determination of proved reserves
    (13,979 )     (8,614 )
Capitalized exploratory well costs charged to expense
    (3,341 )     (293 )
 
           
End of period
    16,370       25,340  
Less exploratory well costs that have been capitalized for a period of one year or less
    (9,501 )     (21,589 )
 
           
Capitalized exploratory well costs that have been capitalized for a period greater than one year
  $ 6,869     $ 3,751  
 
           
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    4       3  
 
           
     As of September 30, 2006, of the $6.9 million of capitalized exploratory well costs that have been capitalized for more than one year, each of the wells have additional exploratory wells in the same prospect area drilling or firmly planned. The $16.4 million of capitalized exploratory well costs at September 30, 2006 was incurred in 2006 ($8.4 million), in 2005 ($5.6 million) and in 2004 ($2.4 million).

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(6) ASSET RETIREMENT OBLIGATIONS
     A reconciliation of our liability for plugging and abandonment costs for the nine months ended September 30, 2006 and 2005 is as follows (in thousands):
                 
    Nine Months Ended  
    September 30,  
    2006     2005  
Beginning of period
  $ 68,063     $ 70,727  
Liabilities incurred
    3,150       3,020  
Acquisitions
    1,433        
Liabilities settled
    (2,973 )     (3,097 )
Accretion expense – continuing operations
    3,412       3,809  
Accretion expense – discontinued operations
    14        
Change in estimate
    3,634       (1,429 )
 
           
End of period
  $ 76,733     $ 73,030  
 
           
     Accretion expense is recognized as a component of depreciation, depletion and amortization.
(7) STOCK-BASED COMPENSATION
     Prior to January 1, 2006, we accounted for stock options granted under our stock-based compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related Interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation.” For our stock options, no stock-based compensation expense was recognized in our statements of operations prior to January 1, 2006, as all stock options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment,” using the modified prospective transition method. Under this transition method, compensation cost for stock options and stock appreciation rights recognized in the first nine months of 2006 includes (a) compensation cost ($8.4 million) for all stock-based payments granted prior to, but not yet vested as of December 31, 2005, based on the remaining service period and the grant date fair value estimated in accordance with the original provisions of Statement No. 123 and (b) compensation cost ($2.7 million) for all stock-based payments granted subsequent to December 31, 2005, based on the service period and the grant-date fair value estimated in accordance with Statement No. 123(R). Pursuant to Statement No. 123(R), results for prior periods have not been restated. Prior to the third quarter of 2006, Statement No. 123(R) expense was included in non-cash stock compensation. Beginning in 2006, stock compensation has been allocated to direct operating expense ($1.0 million), exploration expense ($1.8 million), general and administrative expense ($8.0 million) and $225,000 to transportation and gathering revenues to align Statement No. 123(R) expense with the employee’s cash compensation. All 2006 and 2005 periods presented have been restated to present stock compensation on a consistent basis.
     We also began granting stock settled stock appreciation rights, or SARs, in July 2005 as part of our stock-based compensation plans to reduce the dilutive impact of our equity plans. Prior to January 1, 2006, we accounted for these SARs grants under the recognition and measurement provisions of APB Opinion No. 25, which require expense to be recognized equal to the amount by which the quoted market value exceeded the original grant price on a mark-to-market basis. Therefore, we recognized $5.8 million of compensation cost in the last six months of 2005 related to SARs. The 2005 SARs related expense has been allocated to direct operating expense ($226,000), exploration expense ($551,000), general and administrative expense ($1.8 million) and a $55,000 reduction to transportation and gathering revenues. Beginning January 1, 2006, as required under the provisions of Statement No. 123(R), those SARs granted prior to, but not yet vested as of December 31, 2005, are being expensed over the service period based on grant date fair value estimated in accordance with the original provisions of Statement No. 123 and all SARs granted subsequent to December 31, 2005 are being expensed over the service period based on grant-date fair value estimated in accordance with Statement No. 123(R).
     As a result of adopting Statement No. 123(R) on January 1, 2006, our income from continuing operations before income taxes and net income for the first nine months are $5.1 million and $3.2 million lower, respectively, than if we had continued to account for stock-based compensation under Opinion No. 25. Also, as a result of adopting Statement No. 123(R), our December 31, 2005 unearned deferred compensation and additional paid-in capital related to our restricted stock issuances was eliminated. As of September 30, 2006, there was $13.3 million of unrecognized compensation related to restricted stock awards expected to be recognized over the next 3 years.
     The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of Statement No. 123(R) to options and SARs granted under our stock-based compensation plans in all periods presented. For the purposes of this pro forma disclosure, the value is estimated using a Black-Scholes-Merton option-pricing formula and amortized to expense over the option’s vesting periods.

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    Three Months     Nine Months  
    Ended     Ended  
    September 30,     September 30,  
    2005     2005  
Net income, as reported
  $ 24,665     $ 68,329  
Plus: Total stock-based employee compensation cost included in net income, net of tax
    12,885       19,160  
Deduct: Total stock-based employee compensation, determined under fair value based method, net of tax
    (15,503 )     (25,753 )
 
           
Pro forma net income
  $ 22,047     $ 61,736  
 
           
 
               
Earnings per share:
               
Basic-as reported
  $ 0.19     $ 0.56  
Basic-pro forma
  $ 0.17     $ 0.50  
 
               
Diluted-as reported
  $ 0.19     $ 0.54  
Diluted-pro forma
  $ 0.17     $ 0.48  
     The weighted average fair value of SARs granted in the first nine months of 2006 was determined to be $8.50 based on the following assumptions: risk-free interest rate of 4.8%; dividend yield of 0.3%; expected volatility of 41%; and expected life of 3.53 years.
(8) SUPPLEMENTAL CASH FLOW INFORMATION
                 
    Nine Months Ended
    September 30,
    2006   2005
    (in thousands)
Non-cash investing and financing activities included:
               
Common stock issued under benefit plans
  $ 887     $ 2,431  
Asset retirement costs capitalized
    6,765       1,470  
6.5 million shares issued for Stroud acquisition
    177,641        
Stock options (652,000) assumed in Stroud acquisition
    9,478        
Net working capital assumed in Stroud acquisition
    12,824        
 
               
Net cash provided from operating activities included:
               
Income taxes paid
  $ 86     $ 208  
Interest paid
    39,168       30,421  
(9) INDEBTEDNESS
     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2006, is shown parenthetically). No interest expense was capitalized during the three months or the nine months ended September 30, 2006 and 2005, respectively.
                 
    September 30,     December 31,  
    2006     2005  
Bank debt (6.7%)
  $ 384,700     $ 269,200  
 
               
Subordinated debt:
               
7-3/8% Senior Subordinated Notes due 2013, net of discount
    197,182       196,948  
6-3/8% Senior Subordinated Notes due 2015
    150,000       150,000  
7-1/2% Senior Subordinated Notes due 2016, net of discount
    249,512        
 
           
Total debt
  $ 981,394     $ 616,148  
 
           

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Bank Debt
     On October 25, 2006, we entered into an amended and restated $800.0 million revolving bank facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of $800.0 million or the borrowing base. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. At October 25, 2006, the borrowing base was $800.0 billion. At September 30, 2006, the outstanding balance under the bank credit facility was $384.7 million and there was $415.3 million of borrowing capacity available assuming the amended and restated credit facility was in effect on that date. As part of the amendment, the loan maturity was extended to October 25, 2011. 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 (A) the higher of (1) the prime rate for 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 6.7% and 4.6% for the three months ended September 30, 2006 and 2005, respectively. The weighted average interest rate on the bank credit facility was 6.3% and 4.3% for the nine months ended September 30, 2006 and 2005, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At September 30, 2006, the commitment fee was 0.375% and the interest rate margin was 1.25%. At October 23, 2006, the interest rate (including applicable margin) was 6.6%.
7-3/8% Senior Subordinated Notes due 2013
     In 2003, we issued $100.0 million of 7-3/8% senior subordinated notes due 2013, or the 7-3/8% Notes. In 2004, we issued an additional $100.0 million of 7-3/8% Notes; therefore, $200.0 million of the 7-3/8% Notes is currently outstanding. We pay interest on the 7-3/8% Notes semi-annually in January and July of each year. The 7-3/8% Notes mature in 2013 and are guaranteed by certain of our subsidiaries. The 7-3/8% Notes were issued at a discount which is amortized into interest expense over the life of the 7-3/8% Notes.
     We may redeem the 7-3/8% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices from 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. Prior to July 15, 2006, we may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If we experience a change of control, there may be a requirement to repurchase all or a portion of the 7-3/8% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 7-3/8% Notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our senior debt and will be subordinated to future senior debt that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 7-3/8% Notes.
6-3/8% Senior Subordinated Notes due 2015
     In 2005, we issued $150.0 million of 6-3/8% Senior Subordinated Notes due 2015, or the 6-3/8% Notes. We pay interest on the 6-3/8% Notes semi-annually in March and September of each year. The 6-3/8% Notes mature in 2015 and are guaranteed by certain of our subsidiaries.
     We may redeem the 6-3/8% 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 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. If we experience a change of control, there may be a requirement to repurchase all or a portion of the 6-3/8% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 6-3/8% 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 Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 6-3/8% Notes.
7-1/2% Senior Subordinated Notes due 2016
     In May 2006, we issued $150.0 million of 7-1/2% Senior Subordinated Notes due 2016, or the 7-1/2% Notes. In August 2006, we issued an additional $100.0 million of 7-1/2% Notes; therefore, $250.0 million of the 7-1/2% Notes is currently outstanding. We pay interest on the 7-1/2% Notes semi-annually in May and November of each year. The 7-1/2% Notes mature

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in 2016 and are guaranteed by certain of our subsidiaries. The August 2006 issuance of the 7-1/2% Notes was issued at a discount which is amortized into interest expense over the life of the 7-1/2% Notes.
     We may redeem the 7-1/2% Notes, 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 notes 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 7-1/2% Notes 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 purchase all or a portion of the 7-1/2% Notes at 101% of the principal amount plus accrued and unpaid interest, if any. The 7-1/2% Notes and the guarantees by our subsidiary guarantors are, general, unsecured obligations and are subordinated to our bank debt and will be subordinated to further senior debt that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and the indenture governing the 7-1/2% 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 7-3/8% Notes, the 6-3/8% Notes and the 7-1/2% Notes are full and unconditional and joint and several; any subsidiaries, other than the subsidiary guarantors, are minor subsidiaries.
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, 2006. 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 plus 66-2/3% of net cash proceeds from common stock issuances. Approximately $449.1 million was available under the bank credit facility’s restricted payment basket on September 30, 2006. The terms of the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% 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. At September 30, 2006, $494.2 million was available under the 6-3/8% Notes, the 7-3/8% Notes, and the 7-1/2% Notes restricted payment baskets.
(10) DERIVATIVE ACTIVITIES
     At September 30, 2006, we had open swap contracts covering 69.5 Bcf of gas at prices averaging $9.35 per mcf and 36.8 thousand barrels of oil at prices averaging $35.00 per barrel. We also had collars covering 70.2 Bcf of gas at weighted average floor and cap prices which range from $7.27 to $10.17 per mcf and 4.2 million barrels of oil at weighted average floor and cap prices that range from $52.33 to $65.80 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, or the NYMEX, on September 30, 2006, was a net unrealized pre-tax gain of $108.4 million. The contracts expire monthly through December 2008. Transaction gains and gains on settled contracts are determined monthly and are included as increases or decreases to oil and gas revenues in the period the production is sold. Oil and gas revenues were decreased by $46.6 million and $84.6 million due to realized losses in the nine months ended September 30, 2006 and 2005, respectively. Oil and gas revenues were decreased by $13.5 million and $41.4 million due to realized losses in the three months ended September 30, 2006 and 2005 respectively. Other revenues in our consolidated statements of operations include ineffective hedging gains on hedges that qualified for hedge accounting of $3.5 million and losses of $417,000 in the nine months ended September 30, 2006 and 2005, respectively. Other revenues includes ineffective hedging gains of $184,000 and losses of $665,000 in the three months ended September 30, 2006 and 2005, respectively. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and were marked to market in the first nine months of 2006 which resulted in a gain of $83.7 million in the nine months then ended and a gain of $54.9 million in the three months ended September 30, 2006.

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     The following table sets forth our derivative volumes by year as of September 30, 2006:
                         
Period   Contract Type   Volume Hedged   Average Hedge Price
Natural Gas
                       
2006
  Swaps   10,761 Mmbtu/day   $ 6.48  
2006
  Collars   153,283 Mmbtu/day   $ 6.68 - $8.89  
2007
  Swaps   82,500 Mmbtu/day   $ 9.34  
2007
  Collars   98,500 Mmbtu/day   $ 7.13 - $9.99  
2008
  Swaps   105,000 Mmbtu/day   $ 9.42  
2008
  Collars   55,000 Mmbtu/day   $ 7.93 - $11.40  
 
                       
Crude Oil
                       
2006
  Swaps   400 bbl/day   $ 35.00  
2006
  Collars   6,863 bbl/day   $ 39.83 - $49.05  
2007
  Collars   5,800 bbl/day   $ 52.90 - $64.58  
2008
  Collars   4,000 bbl/day   $ 56.89 - $74.78  
     We have used interest rate swap agreements to manage the interest rate risk under the variable rate bank credit facility which may be adversely affected by volatility in market rates. Our interest rate swap agreements ended on June 30, 2006.
     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. The creditworthiness of the counterparties is subject to continuing review.
(11) COMMITMENTS AND CONTINGENCIES
     We are involved in various legal actions and claims arising in the ordinary course of business, one of which is Jack Freeman, et al. v. Great Lakes Energy Partners L.L.C., et al. This was a class-action suit filed in 2000 against Great Lakes and Range in the state court of Chautauqua County, New York. The plaintiffs were seeking to recover actual damages and expenses plus punitive damages based on allegations that we sold gas to affiliates and gas marketers at low prices, and that inappropriate post production expenses were used to reduce proceeds to the royalty owners, and that improper accounting was used for the royalty owners’ share of gas. A negotiated settlement of $725,000 was agreed to and reflected in general and administrative expense in the fourth quarter of 2005. During the second quarter of 2006, the Court approved the negotiated settlement and in July 2006, this lawsuit was settled at the negotiated amount. In management’s opinion, we are not involved in any litigation, the outcome of which would have a material adverse effect on our financial position, results of operations or liquidity.
     As of September 30, 2006, we have contracts with two drilling contractors to use two drilling rigs with terms of up to two years and minimum future commitments of $3.5 million in 2006, $12.8 million in 2007 and $2.2 million in 2008. Early termination of these contracts at September 30, 2006 would have required us to pay maximum penalties of $14.0 million. We do not expect to pay any early termination penalties related to these contracts. We also entered into a new ten-year office lease which begins in April 2007 with payments of $1.4 million per year for the first five years and $1.6 million for the next five years.

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(12) 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. All shares have been adjusted to reflect the three-for-two common stock split effected on December 2, 2005. The following is a schedule of changes in the number of common shares outstanding from January 1, 2005 to September 30, 2006:
                 
    Nine Months   Twelve Months
    Ended   Ended
    September 30, 2006   December 31, 2005
Beginning balance
    129,907,220       121,829,027  
 
               
Public offerings
          6,900,000  
Shares issued for Stroud acquisition
    6,517,498        
Stock options/SARs exercised
    1,612,645       1,105,549  
Restricted stock
    471,109        
Deferred compensation plan
    11,689       20,885  
Shares issued in lieu of bonuses
    20,686       25,590  
Shares contributed to 401(k) plan
          33,018  
Fractional shares
          (1,023 )
Treasury shares
    5,826       (5,826 )
 
               
 
    8,639,453       8,078,193  
 
               
 
               
Ending balance
    138,546,673       129,907,220  
 
               
Treasury Stock
     In 2005, we bought in open market purchases, 201,000 shares at an average price of $14.00. As of September 30, 2006, all of these shares had been used for equity compensation. The Board of Directors has approved up to $10.0 million of additional repurchases of common stock based on market conditions and opportunities.
(13) 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 (or 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 of the Board of Directors which is made up of independent directors. All awards granted under these plans have been issued at the prevailing market price at the time of the grant. Information with respect to stock option and SARs activities is summarized below:
                 
            Weighted  
            Average  
    Shares     Exercise Price  
Outstanding on December 31, 2005
    8,742,305     $ 9.31  
Granted
    1,613,910       24.29  
Stock options assumed in Stroud acquisition
    652,062       19.67  
Exercised
    (1,689,248 )     8.59  
Expired/forfeited
    (101,714 )     16.43  
 
           
Outstanding on September 30, 2006 (a)
    9,217,315     $ 12.72  
 
           
 
(a)   Includes options outstanding under our inactive plans of 5.4 million under the 1999 Stock Option plan, 252,000 under the Outside Directors’ Stock Option plan, 116,200 under the 1989 Stock Option plan and 382,000 under the Stroud plan. The total outstanding at September 30, 2006 includes 3.1 million SARs.

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     The following table shows information with respect to outstanding stock options and SARs at September 30, 2006:
                                         
    Outstanding     Exercisable  
            Weighted-                      
            Average     Weighted-             Weighted-  
Range of           Remaining     Average             Average  
Exercise Prices   Shares     Contractual Life     Exercise Price     Shares     Exercise Price  
$   1.29 – $   4.99
    2,679,503       3.05     $ 3.60       2,643,502     $ 3.58  
5.00 –      9.99
    1,417,772       2.38       7.01       702,810       7.02  
10.00 –    14.99
    420,293       3.08       11.41       245,242       11.85  
15.00 –    19.99
    2,937,514       4.13       17.04       957,905       17.67  
20.00 –    24.99
    1,639,733       4.65       24.15       138,273       23.84  
25.00 –    27.31
    122,500       4.41       26.31       3,150       25.51  
 
                             
Total
    9,217,315       3.60     $ 12.72       4,690,882     $ 8.02  
 
                             
     As of September 30, 2006, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $115.5 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $80.8 million and 3.53 years. As of September 30, 2006, the number of fully-vested awards and awards expected to vest was 9.0 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $12.53 and 3.59 years and the aggregate intrinsic value was $114.2 million. As of September 30, 2006, unrecognized compensation cost related to the awards was $19.9 million, which is expected to be recognized over a weighted average period of 1.08 years.
Restricted Stock Grants
     During the first nine months of 2006, 476,200 shares of restricted stock (5,100 shares from treasury stock) were issued to directors and employees at an average price of $24.32. These grants included 15,000 issued to directors, which vest immediately and 461,200 to employees with a three-year vesting period. In 2005, we issued 192,500 shares of restricted stock (from treasury stock) as compensation to directors and employees at an average price of $22.47. The restricted grants included 26,200 issued to directors, which vest immediately, and 166,300 to employees with vesting ranging from three to four years. We recorded compensation expense related to these grants which is based upon the market value of the shares on the date of grant of $2.8 million and $632,000 in the nine-month periods ended September 30, 2006 and 2005, respectively.
     A summary of the status of our unvested restricted stock outstanding as of September 30, 2006, and changes during the nine months then ended, is presented below:
                 
            Weighted Average  
            Grant- Date  
    Shares     Fair Value  
Outstanding on January 1, 2006
    251,232     $ 14.21  
Granted
    476,161       24.32  
Vested
    (163,525 )     16.08  
Forfeited
    (6,128 )     16.21  
 
           
Outstanding on September 30, 2006
    557,740     $ 22.27  
 
           
Deferred Compensation Plan
     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan, or the 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 non-cash stock compensation 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

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Trusts. The cost of common stock held in the Rabbi Trusts is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in other comprehensive income, or OCI, changes in the fair value of the liability are charged or credited to non-cash stock compensation expense each quarter. Based on a decline in our stock price of $1.95 for the three months ended September 30, 2006 and $1.10 for the nine months then ended, we recorded non-cash mark-to-market income of $3.3 million in the three months and $562,000 in the nine months ended September 30, 2006. Based on an increase in our stock price of $7.81 for the three months ended September 30, 2005 and $12.10 for the nine months then ended, we recorded non-cash mark-to-market expense of $16.6 million in the three months and $25.9 million in the nine months ended September 30, 2005.
(14) INCOME TAXES
     The significant components of deferred tax liabilities and assets on September 30, 2006 and December 31, 2005 were as follows (in thousands):
                 
    September 30,     December 31,  
    2006     2005  
Deferred tax assets (liabilities)
               
Net unrealized (gain) loss on derivative contracts
  $ (41,266 )   $ 85,462  
Net operating loss carryover
    89,335       76,944  
Other
    80,498       70,524  
Depreciation and depletion
    (595,532 )     (346,070 )
 
           
 
               
Net deferred tax liability
  $ (466,965 )   $ (113,140 )
 
           
     At December 31, 2005, we had regular net operating loss, or NOL, carryovers of $207.2 million and alternative minimum tax, or AMT, NOL carryovers of $179.2 million that expire between 2012 and 2025. At December 31, 2005, we had AMT credit carryovers of $0.7 million that are not subject to limitation or expiration.

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(15) 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,  
    2006     2005     2006     2005  
Numerator:
                               
Income from continuing operations
  $ 65,414     $ 24,665     $ 171,794     $ 68,329  
Loss from discontinued operations
    (14,084 )           (13,519 )      
 
                       
Net income
  $ 51,330     $ 24,665     $ 158,275     $ 68,329  
 
                       
 
                               
Denominator:
                               
Weighted average shares outstanding
    138,318       129,617       133,767       125,156  
Stock held in the deferred compensation plan and treasury shares
    (1,335 )     (2,213 )     (1,341 )     (2,202 )
 
                       
Weighted average shares, basic
    136,983       127,404       132,426       122,954  
 
                       
 
                               
Effect of dilutive securities:
                               
Weighted average shares outstanding
    138,318       129,617       133,767       125,156  
Employee stock options and other
    3,704       2,913       3,699       2,553  
 
                       
Dilutive potential common shares for diluted earnings per share
    142,022       132,530       137,466       127,709  
 
                       
 
                               
Earnings per common share:
                               
Income from continuing operations
                               
-Basic
  $ 0.48     $ 0.19     $ 1.30     $ 0.56  
-Diluted
  $ 0.46     $ 0.19     $ 1.25     $ 0.54  
Income from discontinued operations
                               
-Basic
  $ (0.11 )   $     $ (0.10 )   $  
-Diluted
  $ (0.10 )   $     $ (0.10 )   $  
Net income
                               
-Basic
  $ 0.37     $ 0.19     $ 1.20     $ 0.56  
-Diluted
  $ 0.36     $ 0.19     $ 1.15     $ 0.54  
     Stock appreciation rights (SARs) for 18,000 shares were outstanding but not included in the computations of diluted net income per share for the three month and the nine month periods ended September 30, 2006 because the exercise price of the SARs was greater than the average price of the common shares and would be anti-dilutive to the computations.
(16) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
                 
    September 30,     December 31,  
    2006     2005  
Oil and gas properties:
               
Properties subject to depletion
  $ 3,251,908     $ 2,519,454  
Unproved properties
    209,789       28,636  
 
           
Total
    3,461,697       2,548,090  
Accumulated depletion
    (915,222 )     (806,908 )
 
           
 
             
Net
  $ 2,546,475     $ 1,741,182  
 
           

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(17) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT
                 
    Nine Months     Twelve Months  
    Ended     Ended  
    September 30,     December 31,  
    2006     2005  
Costs incurred (a):
               
Acquisitions:
               
Leasehold purchases (b)
  $ 58,095     $ 20,674  
Proved oil and gas properties
    347,912       131,748  
Unproved property
    132,821        
Purchase price adjustment (c)
    166,891       20,966  
Asset retirement obligations
    1,433       119  
Gas gathering facilities
          8  
 
           
 
    707,152       173,515  
Development
    329,660       252,574  
 
               
Exploration (d)
    49,029       59,539  
 
               
Gas gathering facilities
    14,564       11,415  
 
           
Subtotal
    1,100,405       497,043  
 
               
Asset retirement obligations
    6,765       (1,730 )
 
           
Total
  $ 1,107,170     $ 495,313  
 
           
 
(a)   Includes costs incurred whether capital or expense.
 
(b)   Leasehold acquired for ongoing exploration and development activity.
 
(c)   Represents non-cash gross up to account for difference in book and tax basis of acquisitions.
 
(d)   Includes $34,367 and $29,437 of exploration costs expensed in the nine months ended September 30, 2006 and the twelve months ended December 31, 2005, respectively.
(18) ACCOUNTING STANDARDS NOT YET ADOPTED
     In July 2006, the FASB issued FASB Interpretation (“FIN”) No., 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109 “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties accounting in interim periods and disclosure. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 to determine the impact on our consolidated financial statements.

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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 2005 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this quarterly report on 10-Q.
     Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A in our 2005 Annual Report on Form 10-K and subsequent filings. As discussed in Note 4, we plan to sell the Austin Chalk properties we purchased as part of our Stroud acquisition. The Austin Chalk properties are reflected on our consolidated financial statements as “discontinued operations.” Except where noted, discussions in this report relate to our continuing activities.
Critical Accounting Estimates
     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.
     On January 1, 2006, we adopted the provisions of FASB Statement No. 123(R), “Share-Based Payment.” Statement No. 123(R) is a revision of SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25, “Accounting for Stock Issued to Employees.” Statement No. 123(R) eliminates the option of using the intrinsic value method of accounting previously available, and requires companies to recognize in the financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. See Note 7 to our unaudited financial statements included elsewhere in this Form 10-Q for more information. There have been no other material changes to our critical accounting estimates subsequent to December 31, 2005.

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Results of Operations
     Volumes and sales data:
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2006   2005   2006   2005
Production:
                               
Crude oil (bbls)
    803,224       795,775       2,355,348       2,230,299  
NGLs (bbls)
    277,161       252,654       831,814       748,951  
Natural gas (mcfs)
    20,128,662       16,165,918       54,650,369       46,364,057  
Total (mcfe) (a)
    26,610,972       22,456,492       73,773,341       64,239,557  
 
                               
Average daily production:
                               
Crude oil (bbls)
    8,731       8,650       8,628       8,170  
NGLs (bbls)
    3,013       2,746       3,047       2,743  
Natural gas (mcfs)
    218,790       175,717       200,184       169,832  
Total (mcfe) (a)
    289,250       244,092       270,232       235,310  
 
                               
Average sales prices (excluding hedging):
                               
Crude oil (per bbl)
  $ 64.69     $ 59.90     $ 63.61     $ 52.21  
NGLs (per bbl)
  $ 39.48     $ 32.90     $ 34.88     $ 29.08  
Natural gas (per mcf)
  $ 6.12     $ 7.88     $ 6.85     $ 6.79  
Total (per mcfe) (a)
  $ 7.00     $ 8.17     $ 7.50     $ 7.05  
 
                               
Average sales price (including hedging):
                               
Crude oil (per bbl)
  $ 46.10     $ 41.77     $ 46.66     $ 38.11  
NGLs (per bbl)
  $ 39.48     $ 27.97     $ 34.88     $ 25.26  
Natural gas (per mcf)
  $ 6.19     $ 6.29     $ 6.73     $ 5.70  
Total (per mcfe) (a)
  $ 6.49     $ 6.33     $ 6.87     $ 5.73  
 
                               
Average NYMEX prices (b):
                               
Oil per Bbl
  $ 70.48     $ 63.19     $ 68.22     $ 55.40  
Gas per Mmbtu
  $ 6.53     $ 8.25     $ 7.47     $ 7.12  
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcfe. Excludes discontinued operations.
 
(b)   Based on average of bid week prompt month prices.
Overview
     Total revenues increased 61% for the third quarter of 2006 over the same period of 2005. This increase is due to higher production and realized prices and a favorable mark-to-market value adjustment on oil and gas derivatives. For the third quarter of 2006, production increased 19% from last year due to the continued success of our drilling program and recent acquisitions. Realized oil and gas prices were higher by 2% in the third quarter of 2006 compared to the same period of 2005 reflecting the expiration of our lower-priced oil and gas hedges. Our remaining hedges reduced revenue by $13.5 million in the third quarter of 2006 and by $41.4 million in the same period of 2005.
     Higher production volumes and higher realized oil and gas prices have improved our profit margins. However, it is our belief that Range and the oil and gas industry as a whole continues to experience higher costs due to heightened competition for qualified employees, goods and services. Also, while a significant portion of our production is hedged, market prices for oil and gas have declined during the second and third quarter of 2006. On a unit cost basis, our direct operating costs (excluding non-cash compensation expense) increased $0.18 per mcfe, which reflects a 24% increase from the third quarter of 2005 to the third quarter of 2006. As of the end of the quarter, some services costs have begun to level off and in some cases decline in response to lower oil and gas prices and reduced demand. Other costs, such as interest expense, personnel and general overhead, have continued to increase as we continue to grow our reserves, production volume and drilling inventory.

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Comparison of Quarter Ended September 30, 2006 and 2005
     Net income increased $26.7 million to $51.3 million primarily due to higher realized oil and gas prices, higher production volumes, a favorable mark-to-market value adjustment on oil and gas derivatives and lower price fluctuations on our common stock held in our deferred compensation plan. Oil and gas revenues for the third quarter of 2006 reached $172.6 million and were 22% higher than 2005 due to slightly higher oil and gas prices and a 19% increase in production. A 61% increase in total revenues was partially offset by higher operating costs, DD&A, interest and exploration expense.
     Average realized price received for oil and gas during the third quarter of 2006 was $6.49 per mcfe, up 2% or $0.16 per mcfe from the same quarter of the prior year. The average price received in the third quarter for oil increased 10% to $46.10 per barrel and decreased 2% to $6.19 per mcf for gas from the same period of 2005. The effect of our hedging program decreased realized prices $0.51 per mcfe in the third quarter of 2006 versus a decrease of $1.84 per mcfe in the same period of 2005.
     Production volumes increased 19% from the third quarter of 2005 primarily due to continued drilling success and our integration of recent acquisitions. Our production for the third quarter was 289.3 mmcfe per day of which 56% was attributable to the Southwestern division, 36% to the Appalachian division and 8% to the Gulf Coast division.
     Other revenue increased in 2006 to $249,000 from a loss of $968,000 in 2005. The 2006 period includes $184,000 of ineffective hedging gains. Other revenue for 2005 includes $665,000 of ineffective hedging losses.
     Direct operating expense increased $7.9 million in the third quarter of 2006 to $24.8 million due to higher oilfield service costs, higher volumes and the integration of our recent acquisitions. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $1.7 million ($0.06 per mcfe) of workover costs in 2006 versus $1.4 million ($0.06 per mcfe) in 2005. The workover costs were primarily attributable to workovers on properties located in the Gulf of Mexico (continuing costs associated with the 2005 hurricanes) and the Southwestern properties. Direct operating expenses (excluding non-cash compensation expense) increased $0.18 per mcfe from the same period of 2005. This increase includes higher offshore well insurance ($0.04 per mcfe), surface facility maintenance ($0.03 per mcfe) and water disposal and equipment costs ($0.04 per mcfe).
     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $1.5 million or 18% from the same period of the prior year due to higher volumes and assessed values. Production and ad valorem taxes were $0.38 per mcfe in both 2006 and in 2005.
     Exploration expense increased $8.8 million from the same period of the prior year due principally to higher seismic expenditures ($3.1 million) and higher dry hole expense ($4.9 million). Exploration expense includes exploration personnel costs of $1.8 million in 2006 versus $1.4 million in 2005. The following table details our exploration-related expenses for the third quarter of 2006 and 2005 (in thousands):
                                 
    Three Months Ended September 30,  
 
  2006     2005     Change     %  
Exploration expense:
                              %
Dry hole expense
  $ 5,566     $ 691     $ 4,875       705 %
Seismic
    7,248       4,168       3,080       74 %
Personnel expense
    1,760       1,383       377       27 %
Non-cash compensation expense
    757       568       189       33 %
Other
    1,181       915       266       29 %
 
                       
 
                               
Total
  $ 16,512     $ 7,725     $ 8,787       114 %
 
                       
     General and administrative expense for the third quarter of 2006 increased $3.2 million from 2005 due to $2.8 million of Statement No. 123(R) expenses, higher salaries and benefits ($2.1 million) and higher restricted stock amortization ($802,000), somewhat offset by lower legal and franchise tax expense. The 2005 period also includes $1.8 million of SARs-related expense. On a per mcfe basis, general and administrative expense (excluding non-cash compensation expense) decreased from $0.32 in 2005 to $0.31 in 2006.
     Non-cash stock compensation for the third quarter of 2006 decreased $20.1 million from 2005 primarily due to the decrease in market value of the common stock held in our deferred compensation plan.

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     Interest expense for the third quarter of 2006 increased $7.0 million to $16.9 million due to rising interest rates, higher debt balances and the refinancing of certain debt from floating to higher fixed rates. In May and August 2006, we issued a total of $250.0 million of 7-1/2% Notes which added $3.8 million of interest costs in the third quarter of 2006. The proceeds from the issuance of the 7-1/2% Notes were used to retire lower interest rate floating bank debt. Average debt outstanding on the bank credit facility was $412.9 million and $286.1 million for the third quarter of 2006 and 2005, respectively and the average interest rates were 6.7% and 4.6%, respectively.
     Depletion, depreciation and amortization, or DD&A, increased $13.3 million or 41% to $46.2 million in the third quarter of 2006 with a 19% increase in production and a 16% increase in depletion rates. The acquisition of Stroud increased our depletion rates approximately 12% in the three months ended September 30, 2006. The third quarter of 2006 includes impairment expense on an offshore property of $2.4 million ($0.09 per mcfe) due to declining oil and gas prices. On a per mcfe basis, DD&A increased from $1.47 in the third quarter of 2005 to $1.74 in the third quarter of 2006.
     Income tax expense for 2006 increased to $39.5 million reflecting the 166% increase in income from continuing operations before taxes compared to the same period of 2005. The third quarters of 2006 and 2005 provide for tax expense at an effective rate of approximately 37%. Current income taxes for the three months ended September 30, 2006 of $615,000 represent state income taxes.
     Discontinued operations includes the operating results of our Austin Chalk properties which were acquired as part of the Stroud transaction. The three months ended September 30, 2006 includes $30.4 million of impairment expense due to lower oil and gas prices and production. The impairment expense is the result of a decline in the fair value due to lower oil and gas prices and production since the acquisition date.
     The following table presents information about our operating expenses per mcfe for the three months ended September 30, 2006 and 2005:
                                 
    Three Months Ended September 30,
    2006   2005   Change   %
Direct operating expense (excluding non-cash compensation)
  $ 0.92     $ 0.74     $ 0.18       24 %
Direct operating expense non-cash compensation
    0.01       .01              
Production and ad valorem tax expense
    0.38       0.38              
General and administrative expense (excluding non-cash compensation)
    0.31       0.32       (0.01 )     (3 %)
General and administrative non-cash compensation
    0.15       0.09       0.06       67 %
Interest expense
    0.63       0.44       0.19       43 %
Depletion, depreciation and amortization expense
    1.74       1.47       0.27       18 %
Comparison of the Nine Months Ended September 30, 2006 and 2005
     Net income increased $89.9 million to $158.3 million primarily due to higher realized oil and gas prices, higher production volumes, a favorable mark-to-market value adjustment on oil and gas derivatives and lower price fluctuations on our common stock held in our deferred compensation plan. Oil and gas revenues for the first nine months of 2006 reached $506.6 million and were 38% higher than 2005 due to higher oil and gas prices and a 15% increase in production. A 61% increase in total revenues was partially offset by higher exploration, general and administrative and operating costs, DD&A and interest expense.
     Average realized price received for oil and gas during the first nine months of 2006 was $6.87 per mcfe, up 20% or $1.14 per mcfe from the same period of the prior year. The average price received in the first nine months for oil increased 22% to $46.66 per barrel and increased 18% to $6.73 per mcf for gas from the same period of 2005. The effect of our hedging program decreased realized prices $0.63 per mcfe in the first nine months of 2006 versus a decrease of $1.32 per mcfe in the same period of 2005.
     Production volumes increased 15% from the same period of 2005 primarily due to continued drilling success and our recent acquisitions. Our production for the first nine months of 2006 was 270.2 mmcfe per day of which 54% was attributable to the Southwestern division, 38% to the Appalachian division and 8% to the Gulf Coast division.
     Other revenue increased in 2006 to $3.3 million from a loss of $621,000 in 2005. The 2006 period includes $3.5 million of ineffective hedging gains. Other revenue for 2005 includes $417,000 of ineffective hedging losses and $735,000 of net IPF expenses partially offset by a $110,000 favorable legal settlement.

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     Direct operating expense increased $15.9 million in the first nine months of 2006 to $65.0 million due to higher oilfield service costs, higher volumes and additional costs due to the integration of our recent acquisitions. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $4.3 million ($0.06 per mcfe) of workover costs in 2006 versus $5.1 million ($0.08 per mcfe) in 2005. The workover costs were primarily attributable to workovers on properties located in the Gulf of Mexico (continuing costs associated with the 2005 hurricanes) and the Southwestern properties. Direct operating expenses (excluding non-cash compensation) increased $0.11 per mcfe from the same period of 2005. The nine months ended September 30, 2006 includes $1.0 million ($0.01 per mcfe) of non-cash compensation expense for stock-based compensation awards granted to field employees versus $226,000 of SARs-related expense in the same period of 2005.
     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $7.1 million or 33% from the same period of the prior year due to higher volumes and increasing prices and assessed values. Production and ad valorem taxes increased to $0.38 per mcfe in 2006 from $0.33 per mcfe in the same period of 2005.
     Exploration expense for the nine months of 2006 increased $14.2 million from 2005 due principally to higher dry hole costs ($7.8 million) and higher seismic expenditures ($3.4 million). Exploration expense includes exploration personnel costs of $4.9 million in 2006 versus $4.2 million in 2005. The nine months ended September 30, 2006 includes $1.8 million of non-cash compensation expense as a result of adopting Statement No. 123(R). The following table details our exploration-related expenses for the nine months ended September 30, 2006 and 2005 (in thousands):
                                 
    Nine Months Ended September 30,  
    2006     2005     Change     %  
Exploration expense:
                               
Dry hole expense
  $ 10,314     $ 2,505     $ 7,809       312 %
Seismic
    14,326       10,937       3,389       31 %
Personnel expense
    4,920       4,172       748       18 %
Non-cash compensation
    2,196       584       1,612       276 %
Other
    2,611       1,922       689       36 %
 
                       
 
                               
Total
  $ 34,367     $ 20,120     $ 14,247       71 %
 
                       
     General and administrative expense for the first nine months of 2006 increased $14.2 million from 2005 due to Statement No. 123(R) expense of $8.0 million, higher salaries and benefits ($4.3 million), higher amortization of restricted stock ($1.8 million), higher professional fees ($535,000) and higher office rental expense ($394,000). The 2005 period includes $1.8 million of SARs-related expense. On a per mcfe basis, general and administrative expense (excluding non-cash compensation) increased from $0.31 in 2005 to $0.35 in 2006.
     Non-cash stock compensation for the first nine months of 2006 was $27.1 million lower than the same period of 2005. This expense has declined due the decrease in market value of common stock held in the deferred compensation plan.
     Prior to the third quarter of 2006, all non-cash compensation expense recognized as a result of adopting Statement No. 123(R) was included in the income statement line item non-cash stock compensation expense. The nine months includes a year-to-date reclassification to allocate these expenses to direct operating expense ($645,000), exploration expense ($1.2 million), G&A expense ($5.1 million) and a $145,000 reduction of transportation and gathering revenue, which aligned the expense with the employee’s cash compensation. The $2.7 million of SARs-related expense in 2005 has also been reclassified to direct operating expense ($247,000), exploration expense ($551,000), general and administrative expense ($1.8 million) and a $34,000 reduction of transportation and gathering revenues.
     Interest expense for the first nine months of 2006 increased $11.4 million to $39.5 million due to rising interest rates and the refinancing of certain debt from floating to higher fixed rates. In May and August 2006, we issued a total of $250.0 million of 7-1/2% Notes which added $5.0 million of interest costs in the first nine months of 2006. The proceeds from the issuance of the 7-1/2% Notes were used to retire lower interest bank debt. Average debt outstanding on the bank credit facility was $318.7 million and $319.2 million for the first nine months of 2006 and 2005, respectively and the average interest rates were 6.3% and 4.3%, respectively.
     Depletion, depreciation and amortization, or DD&A, increased $24.5 million or 26% to $117.6 million in the first nine months of 2006 with a 15% increase in production and a 10% increase in depletion rates. The acquisition of Stroud increased our depletion rates approximately 5% in the nine months ended September 30, 2006. The nine months ended September 30, 2006 includes an impairment expense on an offshore well of $2.4 million ($0.03 per mcfe) due to declining oil and gas prices. On a per mcfe basis, DD&A increased from $1.45 in the first nine months of 2005 to $1.59 in the first nine months of 2006.

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     Income tax expense for 2006 increased to $103.3 million reflecting the 151% increase in income from continuing operations before taxes compared to the same period of 2005. The first nine months of 2006 and 2005 provide for a tax expense at an effective rate of approximately 37%. Current income taxes of $1.8 million represent state income taxes. During the second quarter of 2006, we adjusted our deferred tax balances to reflect the enactment of the new Texas franchise tax laws. The impact of the adoption was not material to our statement of operations.
     Discontinued operations includes the operating results of our Austin Chalk properties which were acquired as part of the Stroud transaction. The nine months ended September 30, 2006 includes $30.4 million of impairment expense due to lower oil and gas prices and production. The impairment expense is the result of a decline in fair value due to declining oil and gas prices and production since the acquisition date.
     The following table presents information about our operating expenses per mcfe for the first nine months of September 2006 and 2005:
                                 
    Nine Months Ended September 30,
    2006   2005   Change   %
Direct operating expense (excluding non-cash compensation)
  $ 0.87     $ 0.76     $ 0.11       14 %
Direct operating expense non-cash compensation
    0.01             0.01       100 %
Production and ad valorem tax expense
    0.38       0.33       0.05       15 %
General and administrative expense (excluding non-cash compensation)
    0.35       0.31       0.04       13 %
General and administrative non-cash compensation
    0.14       0.04       0.10       250 %
Interest expense
    0.53       0.44       0.09       20 %
Depletion, depreciation and amortization expense
    1.60       1.45       0.15       10 %
Liquidity and Capital Resources
     During the nine months ended September 30, 2006, our cash provided from operations was $348.1 million and we spent $693.7 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $364.0 million. At September 30, 2006, we had $2.3 million in cash, total assets of $3.1 billion and a debt-to-capitalization ratio of 44.5%. Long-term debt at September 30, 2006 totaled $981.4 million including $384.7 million of bank debt and $596.7 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at September 30, 2006 was $415.3 million (which assumes the new amended and restated credit facility was then in effect).
     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the capital-intensive extractive 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, asset sales 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 or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.
Debt
     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at September 30, 2006. 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 $449.1 million was available under the bank credit facility’s restricted payment basket on September 30, 2006. The terms of the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% 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. Approximately $494.2 million was available under the 6-3/8% Notes, the 7-3/8% Notes and the 7-1/2% Notes restricted payment baskets on September 30, 2006.

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     We maintain an $800.0 million revolving bank credit facility. 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. Redeterminations, other than increases, require the approval of 75% of the lenders while increases require unanimous approval. At October 23, 2006, the bank credit facility had a $800.0 million borrowing base of which $383.3 million was available (assuming the amended and restated credit facility was in effect on that date.)
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, 2006, we have entered into hedging agreements covering 19.1 Bcfe, 78.8 Bcfe and 67.3 Bcfe for 2006, 2007 and 2008, respectively. Net cash provided by operations for the nine months ended September 30, 2006 and 2005 was $348.1 million and $219.0 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes, partially offset by higher operating expenses. Net cash used in investing for the nine months ended September 30, 2006 and 2005 was $714.5 million and $341.5 million, respectively. The 2006 period includes $339.6 million of additions to oil and gas properties and $336.7 million of acquisitions. The 2005 period included $194.1 million of additions to oil and gas properties and $145.3 million of acquisitions. Net cash provided from financing for the nine months ended September 30, 2006 and 2005 was $364.0 million and $105.5 million, respectively. This increase was primarily the result of borrowings to fund acquisitions and capital expenditures and new fixed interest rate notes offset by lower proceeds from equity issuances. During the first nine months of 2006 total debt increased $365.2 million.
Dividends
     On September 1, 2006, the Board of Directors declared a dividend of two cents per share ($2.8 million) on our common stock, which was paid on September 30, 2006 to stockholders of record at the close of business on September 15, 2006.
Capital Requirements
     The 2006 capital budget is currently set at $588.0 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow, borrowings under the bank credit facility and proceeds from asset sales. For the nine months ended September 30, 2006, $378.7 million of development and exploration spending was funded with internal cash flow and borrowings under our credit facility.

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Contractual Cash Obligations
     The following summarizes our contractual financial obligations at September 30, 2006 and their future maturities. We expect to fund these contractual obligation with cash generated from operating activities and refinancing proceeds.
                                         
            2007 and     2009 and              
    2006     2008     2010     Thereafter     Total  
                    (in thousands)                  
Bank debt due 2011 (a)
  $     $     $     $ 384,700     $ 384,700  
7.375% senior subordinated notes (b)
                      200,000       200,000  
6.375% senior subordinated notes (b)
                      150,000       150,000  
7.5% senior subordinated notes (b)
                      250,000       250,000  
Operating leases
    1,393       6,774       5,217       9,728       23,112  
Seismic purchase
    100       400                   500  
Derivative contract liabilities at September 30 fair value
    987       14,340                   15,327  
Asset retirement obligations
    1,214       10,439       4,300       60,780       76,733  
Drilling contracts
    3,499       14,990                   18,489  
 
                             
Total contractual obligations (c)
  $ 7,193     $ 46,943     $ 9,517     $ 1,055,208     $ 1,118,861  
 
                             
 
(a)   Due at termination date of our bank credit facility, which we expect to renew, but there is no assurance that can be accomplished. Interest paid on our bank credit facility would be approximately $25.8 million each year assuming no change in the interest rate or outstanding balance.
 
(b)   We expect to make annual interest payments of $14.8 million per year on our $200.0 million of 7.375% Notes, payments of $9.6 million per year on our $150.0 million of 6.375% Notes and payments of $18.7 million per year on our $250.0 million of 7.5% Notes.
 
(c)   This table does not include the liability for the deferred compensation plan since these obligations will be funded with existing plan assets.
Other Contingencies
     We are involved in various legal actions and claims arising in the ordinary course of business as described in Footnote 11 of the notes to consolidated financial statements. 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 hedging agreements to reduce the impact of oil and gas price volatility on our operations. At September 30, 2006, swaps were in place covering 69.5 Bcf of gas at prices averaging $9.35 per mcf and 36.8 thousand barrels of oil at prices averaging $35.00 per barrel. We also have collars covering 70.2 Bcf of gas at weighted average floor and cap prices which range from $7.27 to $10.17 per mcf and 4.2 million barrels of oil at weighted average floor and cap prices that range from $52.33 to $65.80 per barrel. Their fair value at September 30, 2006 (the estimated amount that would be realized on termination based on contract price and a reference price, generally NYMEX) was a net unrealized pre-tax gain of $108.4 million. Gains and losses 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 is recognized in earnings quarterly in other revenue. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting and were marked to market in the first nine months of 2006 resulting in a gain of $83.7 million.

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     At September 30, 2006, the following commodity derivative contracts were outstanding:
                         
Period   Contract Type   Volume Hedged   Average Hedge Price
Natural Gas
                       
2006
  Swaps   10,761 Mmbtu/day   $ 6.48  
2006
  Collars   153,283 Mmbtu/day   $ 6.68 - $8.89  
2007
  Swaps   82,500 Mmbtu/day   $ 9.34  
2007
  Collars   98,500 Mmbtu/day   $ 7.13 - $9.99  
2008
  Swaps   105,000 Mmbtu/day   $ 9.42  
2008
  Collars   55,000 Mmbtu/day   $ 7.93 - $11.40  
 
                       
Crude Oil
                       
2006
  Swaps   400 bbl/day   $ 35.00  
2006
  Collars   6,863 bbl/day   $ 39.83 - $49.05  
2007
  Collars   5,800 bbl/day   $ 52.90 - $64.58  
2008
  Collars   4,000 bbl/day   $ 56.89 - $74.78  
Inflation and Changes in Prices
     Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by interest rates, changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During the third quarter of 2006, we received an average of $64.69 per barrel of oil and $6.12 per mcf of gas before hedging compared to $59.90 per barrel of oil and $7.88 per mcf of gas in the same period of the prior year. Increases in commodity prices and the increased demand for services can cause inflationary pressures specific to the industry to increase for both services and personnel costs. We expect these costs to continue to increase during the next twelve months.
Accounting Standards Not Yet Adopted
     In July 2006, the FASB issued FASB Interpretation (“FIN”) No., 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109 “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties accounting in interim periods and disclosure. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 to determine the impact on our consolidated financial statements.

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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 price volatility. 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. Hedging is intended to reduce the impact of oil and gas price fluctuations. A portion of our hedges are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our hedging program also includes collars which establish a minimum floor price and a maximum ceiling price. In times of increasing price volatility, we may experience losses from our hedging arrangements and increased basis differentials at the delivery points where we market our production. Widening basis differentials occur when the physical delivery market prices do not increase proportionately to the increased prices in the financial trading markets. Realized gains or losses 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 OCI. 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 are recognized in earnings in other revenues. We do not enter into derivative instruments for trading purposes.
     As of September 30, 2006, we had oil and gas swap hedges in place covering 69.5 Bcf of gas and 36.8 thousand barrels of oil at prices averaging $9.35 per mcf and $35.00 per barrel. We also had collars covering 70.2 Bcf of gas at weighted average floor and cap prices which range from $7.27 to $10.17 per mcf and 4.2 million barrels of oil at weighted average floor and cap prices that range from $52.33 to $65.80 per barrel. 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 $108.4 million at that date. These contracts expire monthly through December 2008. 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. Net realized losses relating to these derivatives for the nine months ended September 30, 2006 and 2005 were $46.6 million and $84.6 million, respectively. Losses or gains due to commodity hedge ineffectiveness are recognized in earnings in other revenues in our consolidated statement of operations. The ineffective portion of hedges was a gain of $3.5 million in the nine months of 2006 and a loss of $417,000 in the nine months of 2005. As of the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting were marked to market in the first nine months of 2006 as a gain of $83.7 million.
     In the first nine months of 2006, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $55.2 million. If oil and gas future prices at September 30, 2006 declined 10%, the unrealized hedging gain on September 30, 2006 of $108.4 million would have increased to a gain of $199.0 million.
     Interest rate risk. At September 30, 2006, we had $981.4 million of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Senior debt totaling $384.7 million bore interest at floating rates averaging 6.7%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $3.8 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 13a-15(e) of 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 6. Exhibits
(a)   EXHIBITS
     
Exhibit    
Number   Description
31.1*
  Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
31.2*
  Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32.1**
  Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
   
32.2**
  Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
*   filed herewith
 
**   Furnished herewith

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  RANGE RESOURCES CORPORATION
 
 
  By:   /s/ ROGER S. MANNY    
    Roger S. Manny   
    Senior Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)   
 
October 25, 2006

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     Exhibit index
     
Exhibit    
Number   Description
31.1*
  Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
31.2*
  Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32.1**
  Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
   
32.2**
  Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
*   filed herewith
 
**   Furnished herewith

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