e10vq
 
 
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 June 30, 2011
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
(State or Other Jurisdiction of Incorporation or Organization)
  34-1312571
(IRS Employer Identification No.)
     
100 Throckmorton Street, Suite 1200
Fort Worth, Texas

(Address of Principal Executive Offices)
  76102
(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 has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).
Yes þ     No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large Accelerated Filer þ
  Accelerated Filer o   Non-Accelerated Filer o   Smaller Reporting Company o
    (Do not check if smaller reporting company)
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o     No þ
     161,058,704 Common Shares were outstanding on July 22, 2011.
 
 

 


 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 2011
     Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.
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PART I — FINANCIAL INFORMATION
ITEM 1.   Financial Statements
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
                 
    June 30, 2011     December 31, 2010  
    (Unaudited)        
Assets
               
Current assets:
               
Cash and cash equivalents
  $ 288,839     $ 2,848  
Accounts receivable, less allowance for doubtful accounts of $3,842 and $5,001
    66,772       76,683  
Unrealized derivative gain
    53,674       123,255  
Assets of discontinued operations
    16,351       876,304  
Inventory and other
    11,912       21,352  
Deferred tax asset
    6,340        
 
           
Total current assets
    443,888       1,100,442  
 
           
 
               
Unrealized derivative gain
    11,843        
Equity method investments
    139,935       155,105  
Natural gas and oil properties, successful efforts method
    5,999,665       5,390,391  
Accumulated depletion and depreciation
    (1,447,300 )     (1,306,378 )
 
           
 
    4,552,365       4,084,013  
 
           
Transportation and field assets
    121,905       134,980  
Accumulated depreciation and amortization
    (64,459 )     (60,931 )
 
           
 
    57,446       74,049  
Other assets
    104,430       84,977  
 
           
Total assets
  $ 5,309,907     $ 5,498,586  
 
           
 
               
Liabilities
               
Current liabilities:
               
Accounts payable
  $ 246,549     $ 289,109  
Asset retirement obligations
    4,020       4,020  
Accrued liabilities
    53,077       60,082  
Deferred tax liability
          11,848  
Accrued interest
    29,013       32,189  
Unrealized derivative loss
          352  
Current liabilities of discontinued operations
    19,381       32,962  
 
           
Total current liabilities
    352,040       430,562  
 
           
Bank debt
          274,000  
Subordinated notes
    1,787,398       1,686,536  
Deferred tax liability
    685,200       672,041  
Unrealized derivative loss
    4,427       13,412  
Deferred compensation liability
    159,024       134,488  
Asset retirement obligations and other liabilities
    76,891       59,885  
Long-term liabilities of discontinued operations
          3,901  
Commitments and contingencies
               
 
               
Stockholders’ Equity
               
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding
           
Common stock, $0.01 par, 475,000,000 shares authorized, 160,998,360 issued at June 30, 2011 and 160,113,608 issued at December 31, 2010
    1,610       1,601  
Common stock held in treasury, 175,653 shares at June 30, 2011 and 204,556 shares at December 31, 2010
    (6,489 )     (7,512 )
Additional paid-in capital
    1,848,767       1,820,503  
Retained earnings
    355,099       341,699  
Accumulated other comprehensive income
    45,940       67,470  
 
           
Total stockholders’ equity
    2,244,927       2,223,761  
 
           
Total liabilities and stockholders’ equity
  $ 5,309,907     $ 5,498,586  
 
           
See the accompanying notes.

3


 

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per share data)
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
Revenues and other income
                               
Natural gas, NGL and oil sales
  $ 256,687     $ 173,153     $ 483,568     $ 360,826  
Transportation and gathering
    (1,041 )     663       (728 )     2,744  
Derivative fair value income
    53,039       6,546       12,205       48,879  
(Loss) gain on the sale of assets
    (1,621 )     10,176       (1,482 )     78,089  
Other
    (435 )     637       642       (938 )
 
                       
Total revenues and other income
    306,629       191,175       494,205       489,600  
 
                       
 
                               
Costs and expenses
                               
Direct operating
    28,509       21,171       57,226       43,007  
Production and ad valorem taxes
    7,550       5,663       14,429       12,205  
Exploration
    11,592       14,420       38,779       28,559  
Abandonment and impairment of unproved properties
    18,900       9,727       35,437       16,278  
General and administrative
    39,120       35,836       73,079       64,006  
Termination costs
                      7,938  
Deferred compensation plan
    (5,778 )     (14,135 )     24,852       (19,847 )
Interest expense
    31,383       21,271       56,162       42,202  
Loss on early extinguishment of debt
    18,580             18,580        
Depletion, depreciation and amortization
    78,294       67,813       150,510       132,620  
Impairment of proved properties
                      6,505  
 
                       
Total costs and expenses
    228,150       161,766       469,054       333,473  
 
                       
 
                               
Income from continuing operations before income taxes
    78,479       29,409       25,151       156,127  
 
                               
Income tax expense
                               
Current
    8             8        
Deferred
    32,695       11,763       12,798       60,775  
 
                       
Total income tax expense
    32,703       11,763       12,806       60,775  
 
                       
 
                               
Income from continuing operations
    45,776       17,646       12,345       95,352  
Discontinued operations, net of taxes
    5,517       (8,594 )     13,915       (8,721 )
 
                       
Net income
  $ 51,293     $ 9,052     $ 26,260     $ 86,631  
 
                       
 
                               
Income per common share
                               
Basic-income from continuing operations
  $ 0.28     $ 0.11     $ 0.08     $ 0.59  
— discontinued operations
    0.04       (0.05 )     0.08       (0.05 )
 
                       
— net income
  $ 0.32     $ 0.06     $ 0.16     $ 0.54  
 
                       
 
                               
Diluted-income from continuing operations
  $ 0.28     $ 0.11     $ 0.08     $ 0.59  
— discontinued operations
    0.04       (0.05 )     0.08       (0.05 )
 
                       
— net income
  $ 0.32     $ 0.06     $ 0.16     $ 0.54  
 
                       
 
                               
Dividends per common share
  $ 0.04     $ 0.04     $ 0.08     $ 0.08  
 
                       
 
                               
Weighted average common shares outstanding
                               
Basic
    157,997       156,820       157,772       156,608  
Diluted
    158,833       158,472       158,729       158,601  
See the accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
                 
    Six Months Ended June 30,  
    2011     2010  
Operating activities
               
Net income
  $ 26,260     $ 86,631  
Adjustments to reconcile net cash provided from operating activities:
               
(Gain) loss from discontinued operations
    (13,915 )     8,721  
Loss from equity method investments, net of distributions
    19,259       985  
Deferred income tax expense
    12,798       60,775  
Depletion, depreciation, amortization and proved property impairment
    150,510       139,126  
Exploration dry hole costs
    6        
Mark-to-market gain on gas and oil derivatives not designated as hedges
    (8,103 )     (42,169 )
Abandonment and impairment of unproved properties
    35,437       16,278  
Unrealized derivative gain
    (6,502 )     (11 )
Allowance for bad debts
    (404 )      
Deferred and stock-based compensation
    48,161       5,866  
Amortization of deferred financing costs, loss on extinguishment of debt and other
    19,891       2,367  
Loss (gain) on sale of assets
    1,483       (78,089 )
Changes in working capital:
               
Accounts receivable
    (4,159 )     8,061  
Inventory and other
    2,747       338  
Accounts payable
    (6,222 )     13,859  
Accrued liabilities and other
    (436 )     (14,038 )
 
           
Net cash provided from continuing operations
    276,811       208,700  
Net cash provided from discontinued operations
    36,802       51,737  
 
           
Net cash provided from operating activities
    313,613       260,437  
 
           
 
               
Investing activities
               
Additions to oil and gas properties
    (535,307 )     (322,395 )
Additions to field service assets
    (2,830 )     (10,270 )
Acreage and proved property purchases
    (73,070 )     (187,192 )
Other assets
          (45 )
Proceeds from disposal of assets
    23,409       318,632  
Purchase of marketable securities held by the deferred compensation plan
    (8,832 )     (14,553 )
Proceeds from the sales of marketable securities held by the deferred compensation plan
    6,620       13,296  
 
           
Net cash used in investing activities from continuing operations
    (590,010 )     (202,527 )
Investing activities of discontinued operations
    835,147       (27,011 )
 
           
Net cash provided from (used in) investing activities
    245,137       (229,538 )
 
           
 
               
Financing activities
               
Borrowing on credit facilities
    490,826       371,000  
Repayment on credit facilities
    (764,826 )     (220,000 )
Dividends paid
    (12,860 )     (12,768 )
Issuance of common stock
    554       5,785  
Issuance of subordinated notes
    500,000        
Repayment of subordinated notes
    (413,332 )      
Debt issuance costs
    (21,653 )      
Change in cash overdrafts
    (58,265 )     (13,385 )
Proceeds from the sales of common stock held by the deferred compensation plan
    6,797       4,560  
 
           
Net cash (used in) provided from financing activities
    (272,759 )     135,192  
 
           
 
               
Increase in cash and equivalents
    285,991       166,091  
Cash and cash equivalents at beginning of period
    2,848       767  
 
           
Cash and cash equivalents at end of period
  $ 288,839     $ 166,858  
 
           
See the accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
 
                               
Net income
  $ 51,293     $ 9,052     $ 26,260     $ 86,631  
Other comprehensive (loss) income:
                               
Realized gain on hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of taxes
    (15,178 )     (11,371 )     (39,068 )     (12,124 )
Change in unrealized deferred hedging gains (losses), net of taxes
    17,424       (4,257 )     17,537       48,325  
 
                       
Total comprehensive income (loss)
  $ 53,539     $ (6,576 )   $ 4,729     $ 122,832  
 
                       
See the accompanying notes.

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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
(1) ORGANIZATION AND NATURE OF BUSINESS
     We are a Fort Worth, Texas-based independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties, mostly in the Appalachia and the Southwest regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range Resources Corporation is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”
(2) BASIS OF PRESENTATION
Presentation
     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2010 Annual Report on Form 10-K filed on March 1, 2011 and our current report on Form 8-K filed on May 6, 2011. The results of operations for the quarter and the six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements.
Discontinued Operations
     In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale assets. In April 2011, we completed the sale of most of these assets. We expect to close on the remainder of the sale in the third quarter 2011. We have classified the assets and liabilities of these assets as discontinued operations in the accompanying consolidated balance sheets along with the historic results of these operations as discontinued operations, net of tax, in the accompanying consolidated statements of operations. See also Note 4 and 5 for more information regarding the sale of our Barnett Shale assets.
(3) NEW ACCOUNTING STANDARDS
     In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”).” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. We are currently evaluating the effect that the provisions of this pronouncement will have on our financial statements.
     In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income” which was issued to enhance comparability between entities that report under U.S. GAAP and IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption of the new guidance is permitted and full retrospective application is required. We are currently evaluating the effect that the provisions of this pronouncement will have on our financial statements.
(4) DISPOSITIONS
2011 Asset Sales
     In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale natural gas properties in the Barnett Shale Play located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties), which also included the assumption of certain derivative contracts by the buyer and is subject to normal post closing adjustments. We closed substantially all of this sale in second quarter 2011, for gross cash proceeds of approximately

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$877.0 million, including the derivative contracts assumed. This transaction is subject to additional closings on certain properties subject to preferential rights along with other post-closing adjustments. We expect to close the remainder of the sale in the third quarter 2011. The agreements have an effective date of February 1, 2011 and consequently operating net revenues after February 1, 2011 were a downward adjustment to the selling price. We recorded a pretax gain of $3.8 million in discontinued operations related to this sale. In the accompanying December 31, 2010 balance sheet, we have classified these assets and liabilities as discontinued operations. As indicated in Note 2 and 5, the historic results of our Barnett operations are presented as discontinued operations.
     As part of the sale of our Barnett properties, certain derivative contracts were assumed by the buyer. This resulted in a loss of $1.7 million in second quarter 2011. Under cash flow hedge accounting, an $18.8 million pretax gain related to these hedges is included in accumulated other comprehensive income at June 30, 2011 and will be recognized in earnings during the remainder of 2011 as the hedged production occurs. The hedges assumed as part of the sale were not designated to our Barnett production and were sold to balance our volumes hedged.
2010 Asset Sales
     In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder in June 2010. Proceeds received in first six months 2010 were approximately $323.0 million and we recorded a gain of $77.4 million in continuing operations. The agreement had an effective date of January 1, 2010, and consequently operating net revenues after January 1, 2010 were a downward adjustment to the selling price. The proceeds we received were placed in a like-kind exchange account and in June 2010, we used a portion of the proceeds to purchase proved and unproved natural gas properties in Virginia. In September 2010, the like-kind exchange account was closed and the balance of these proceeds ($135.0 million) was used to repay amounts outstanding under our bank credit facility.
(5) DISCONTINUED OPERATIONS
     The following table presents the components of our Barnett operations as discontinued operations for the three months and the six months ended June 30, 2011 and 2010 (in thousands):
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011     2010     2011     2010  
Revenues and other income
                               
Natural gas, NGL and oil sales
  $ 10,777     $ 33,631     $ 53,034     $ 82,718  
Transportation and gathering
    1       11       6       23  
Gain on the sale of assets
    3,820             3,820       955  
Other
                4        
 
                       
Total revenues and other income
    14,598       33,642       56,864       83,696  
 
                       
 
                               
Costs and expenses
                               
Direct operating
    2,169       8,604       10,446       17,808  
Production and ad valorem taxes
    184       2,427       1,250       3,955  
Exploration
    5       53       37       549  
Abandonment and impairment of unproved properties
          3,770             9,626  
Interest expense
    3,715       9,508       14,791       18,864  
Depletion, depreciation and amortization
    14       23,184       8,894       47,003  
 
                       
Total costs and expenses
    6,087       47,546       35,418       97,805  
 
                       
 
                               
Income (loss) from discontinued operations before income taxes
    8,511       (13,904 )     21,446       (14,109 )
 
                               
Income tax expense (benefit)
                               
Current
                       
Deferred
    2,994       (5,310 )     7,531       (5,388 )
 
                       
Total income tax expense (benefit)
    2,994       (5,310 )     7,531       (5,388 )
 
                       
 
                               
Net income (loss) from discontinued operations
  $ 5,517     $ (8,594 )   $ 13,915     $ (8,721 )
 
                       

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     The carrying values of our Barnett operations are included in discontinued operations in the accompanying consolidated balance sheets which are comprised of the following (in thousands):
                 
    June 30,     December 31,  
    2011     2010  
Composition of assets of discontinued operations:
               
Natural gas and oil properties, net
  $ 12,546     $ 838,044  
Transportation and field assets, net
          684  
Accounts receivable
    3,805       29,300  
Unrealized derivative gain
          8,195  
Inventory and other
          81  
 
           
Total assets of discontinued operations
  $ 16,351     $ 876,304  
 
           
 
               
Composition of liabilities of discontinued operations:
               
Account payable
  $ 12,592     $ 23,366  
Accrued liabilities
    6,789       9,596  
 
           
Total current liabilities of discontinued operations
  $ 19,381     $ 32,962  
 
           
 
               
Asset retirement obligations
  $     $ 1,980  
Other liabilities
          1,921  
 
           
Total long-term liabilities of discontinued operations
  $     $ 3,901  
 
           
(6) INCOME TAXES
     Income tax expense from continuing operations was as follows (in thousands):
                                 
    Three Months Ended   Six Month Ended
    June 30,   June 30,
    2011   2010   2011   2010
 
                               
Income tax expense
  $ 32,703     $ 11,763     $ 12,806     $ 60,775  
Effective tax rate
    41.7 %     40.0 %     50.9 %     38.9 %
     We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended June 30, 2011 and 2010, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences. For the six months ended June 30, 2011 and 2010, our overall effective rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences.

9


 

(7) INCOME FROM CONTINUING OPERATIONS PER COMMON SHARE
     Basic income or loss from continuing operations per share is computed as (i) income or loss from continuing operations (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss from continuing operations per share is computed as (i) basic income or loss from continuing operations attributable to common shareholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. The following table sets forth a reconciliation of income from continuing operations to basic income from continuing operations attributable to common shareholders and to diluted income from continuing operations attributable to common shareholders and a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands except per share amounts):
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Numerator:
                               
Income from continuing operations
  $ 45,776     $ 17,646     $ 12,345     $ 95,352  
Less: Basic income allocable to participating securities (a)
    (808 )     (159 )     (220 )     (1,491 )
 
                       
Basic income from continuing operations attributable to common shareholders
    44,968       17,487       12,125       93,861  
Diluted adjustments to income allocable to participating securities (a)
    4             1       16  
 
                       
Diluted income from continuing operations attributable to common shareholders
  $ 44,972     $ 17,487     $ 12,126     $ 93,877  
 
                       
 
                               
Denominator:
                               
Weighted average common shares outstanding — basic
    157,997       156,820       157,772       156,608  
Effect of dilutive securities:
                               
Employee stock options and SARs
    836       1,652       957       1,993  
 
                       
Weighted average common shares — diluted
    158,833       158,472       158,729       158,601  
 
                       
 
                               
Income from continuing operations per common share:
                               
Basic — net income
  $ 0.28     $ 0.11     $ 0.08     $ 0.59  
Diluted — net income
  $ 0.28     $ 0.11     $ 0.08     $ 0.59  
 
(a)   Restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Restricted stock awards do not participate in undistributed net losses.
     The weighted average common shares — basic for the three months ended June 30, 2011 and 2010 exclude 2.8 million shares of restricted stock which is held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Weighted average common shares-basic for the six months ended June 30, 2011 excludes 2.9 million shares of restricted stock compared to 2.7 million for the six months ended June 30, 2010. SARs of 860,000 for the three months ended June 30, 2011 and 1.0 million for the six months ended June 30, 2011 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares. SARs of 1.1 million for the three months ended June 30, 2010 and 1.1 million for the six months ended June 30, 2010 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares.

10


 

(8) SUSPENDED EXPLORATORY WELL COSTS
     The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2011 and the year ended December 31, 2010 (in thousands):
                 
    June 30,     December 31,  
    2011     2010  
Beginning balance at January 1
  $ 23,908     $ 19,052  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    35,463       28,897  
Reclassifications based on determination of proved reserves
    (11,619 )     (24,041 )
Capitalized exploratory well costs charged to expense
           
 
           
Balance at end of period
    47,752       23,908  
Less exploratory well costs that have been capitalized for a period of one year or less
    (42,519 )     (13,181 )
 
           
Capitalized exploratory well costs that have been capitalized for a period greater than one year
  $ 5,233     $ 10,727  
 
           
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    3       4  
 
           
     As of June 30, 2011, of the $5.2 million of capitalized exploratory well costs that have been capitalized for more than one year, two of the wells are Marcellus Shale wells and are waiting on the completion of pipelines. The following provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of June 30, 2011 (in thousands):
                                         
    Total     2011     2010     2009     2008  
 
                                       
Capitalized exploratory well costs that have been capitalized for more than one year
  $ 5,233     $ 255     $ 334     $ 3,065     $ 1,579  
 
                             
(9) INDEBTEDNESS
     We had the following debt outstanding as of the dates shown below (in thousands). No interest expense was capitalized during the three months and the six months ended June 30, 2011 and 2010.
                 
    June 30,     December 31,  
    2011     2010  
Bank debt
  $     $ 274,000  
 
               
Subordinated debt:
               
6.375% Senior Subordinated Notes due 2015
          150,000  
7.5% Senior Subordinated Notes due 2016, net of discount
          249,683  
7.5% Senior Subordinated Notes due 2017
    250,000       250,000  
7.25% Senior Subordinated Notes due 2018
    250,000       250,000  
8.0% Senior Subordinated Notes due 2019, net of discount
    287,398       286,853  
6.75% Senior Subordinated Notes due 2020
    500,000       500,000  
5.75% Senior Subordinated Notes due 2021
    500,000        
 
           
Total debt
  $ 1,787,398     $ 1,960,536  
 
           

11


 

Bank Debt
     In February 2011, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. Our new borrowing base was set without our Barnett Shale assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On June 30, 2011, the borrowing base was $2.0 billion and our facility amount was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-seven commercial banks with no one bank holding more than 7% of the total facility. The facility amount may be increased up to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility amount increase. At June 30, 2011, we had no outstanding balances under our bank credit facility and we had $13.9 million of undrawn letters of credit leaving approximately $1.5 billion of borrowing capacity available under the facility amount. The facility matures in February 2016. Borrowing under the bank credit facility can either be the Alternate Base Rate (as defined) plus a spread ranging from 0.50% to 1.50% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.50% to 2.50%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 2.0% for the three months ended June 30, 2011 compared to 2.2% for the three months ended June 30, 2010. The weighted average interest rate on the bank credit facility was 2.2% for the six months ended June 30, 2011 compared to 2.2% for the six months ended June 30, 2010. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At June 30, 2011, the commitment fee was 0.375%.
Senior Subordinated Notes
     In May 2011, we issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021 (“5.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 5.75% Notes were issued at par. Interest on the 5.75% Notes is payable semi-annually in June and December and is guaranteed by all of our current subsidiaries. We may redeem the 5.75% Notes, in whole or in part, at any time on or after June 1, 2016, at redemption prices of 102.875% of the principal amount as of June 1, 2016 declining to 100.0% on June 1, 2019 and thereafter. Before June 2014, we may redeem up to 35% of the original aggregate principal amount of the 5.75% Notes at a redemption price equal to 105.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.75% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. On closing, we used $112.9 million of the proceeds to purchase our 6.375% senior subordinated notes due 2015 and $207.1 million of the proceeds to purchase our 7.5% senior subordinated notes due 2016 as part of the tender offer and redemption described below.
     On May 11, 2011, we commenced cash tender offers to purchase the entire outstanding $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and $250.0 million principal amount of our 7.5% senior subordinated notes due 2016. On May 25, 2011, after the expiration of the tender offers, we accepted for purchase $108.9 million in principal of the 2015 notes at 102.375% of par and $198.8 million in principal of the 2016 notes for 104.00% of par. We subsequently called the remaining 2015 and 2016 notes, redeeming all of the remaining outstanding 2015 notes ($41.1 million) at 102.125% of par on June 24, 2011 and redeeming all of the remaining outstanding 2016 notes ($51.2 million) at 103.75% of par on June 24, 2011. During the second quarter 2011, we recognized an $18.6 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.
Debt Covenants
     Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at June 30, 2011.
     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates or change the nature of our business. At June 30, 2011, we were in compliance with these covenants.

12


 

(10) ASSET RETIREMENT OBLIGATIONS
     Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. A reconciliation of our liability for plugging, abandonment and remediation costs for the six months ended June 30, 2011 is as follows (in thousands):
         
    Six Months  
    Ended  
    June 30,  
    2011  
Beginning of period — continuing operations
  $ 60,693  
Liabilities incurred
    1,447  
Liabilities settled
    (1,625 )
Accretion expense — continuing operations
    2,580  
Change in estimate
    11,270  
 
     
End of period — continuing operations
  $ 74,365  
 
     
     Accretion expense is recognized as a component of depreciation, depletion and amortization expense on our consolidated statements of operations.
(11) CAPITAL STOCK
     We have authorized capital stock of 485 million shares, which includes 475 million shares of common stock and 10 million shares of preferred stock. The following is a summary of changes in the number of common shares outstanding since the beginning of 2010:
                 
    Six Months   Year
    Ended   Ended
    June 30,   December 31,
    2011   2010
Beginning balance
    159,909,052       158,118,937  
Stock options/SARs exercised
    558,161       991,988  
Restricted stock grants
    326,591       405,127  
Treasury shares issued
    28,903       12,771  
Shares issued for acreage purchases
          380,229  
 
               
Ending balance
    160,822,707       159,909,052  
 
               
Treasury Stock
     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities and on June 30, 2011, we have $6.8 million remaining under this authorization.
(12) DERIVATIVE ACTIVITIES
     We use commodity—based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap, collar or call option contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Historically, our derivative activities have consisted of collars and fixed price swaps. At June 30, 2011, we had open swap contracts covering 25.6 Bcf of natural gas at prices averaging $5.00 per mcf and 3.1 million barrels of NGLs (the C5 component of NGLs) at prices averaging $103.24 per barrel. At June 30, 2011, we had collars covering 189.1 Bcf of natural gas at weighted average floor and cap prices of $5.27 to $5.93 per mcf and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 to $80.00 per barrel. At June 30, 2011, we also had sold call options for 2.7 million barrels of oil at a weighted average price of $83.15. In first quarter 2011, we entered into NGL derivative swap contracts for the natural gasoline (or C5) component of natural gas liquids. The fair value of our commodity derivatives, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price, generally

13


 

New York Mercantile Exchange (“NYMEX”), on June 30, 2011, was a net unrealized pre-tax gain of $61.1 million. These contracts expire monthly through December 2013.
     The following table sets forth our derivative volumes and average hedge prices as of June 30, 2011:
                 
            Average
Period   Contract Type   Volume Hedged   Hedge Price
Natural Gas
               
2012
  Swaps   70,192 Mmbtu/day   $ 5.00  
2011
  Collars   333,200 Mmbtu/day   $ 5.38-$6.23  
2012
  Collars   189,641 Mmbtu/day   $ 5.32-$5.91  
2013
  Collars   160,000 Mmbtu/day   $ 5.09-$5.65  
 
               
Crude Oil
               
2012
  Collars   2,000 bbls/day   $ 70.00-$80.00  
2011
  Call options   5,500 bbls/day   $ 80.00  
2012
  Call options   4,700 bbls/day   $ 85.00  
 
               
NGLs (Natural gasoline)
               
2011
  Swaps   7,000 bbls/day   $ 104.17  
2012
  Swaps   5,000 bbls/day   $ 102.59  
     Every derivative instrument is recorded on the accompanying balance sheets as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives that qualify for hedge accounting are recorded as a component of accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets, which is later transferred to natural gas, NGL and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Amounts included in AOCI at June 30, 2011 and December 31, 2010 relate solely to our commodity derivative activities. As of June 30, 2011, an unrealized pre-tax derivative gain of $73.5 million was recorded in AOCI. This gain is expected to be reclassified into earnings as a $44.1 million gain in 2011, a $21.9 million gain in 2012 and a $7.5 million gain in 2013. The actual reclassification to earnings will be based on market prices at the contract settlement date.
     For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to natural gas, NGL and oil sales in the period the hedged production is sold. Natural gas, NGL and oil sales include $24.3 million of gains in the three months ended June 30, 2011 compared to gains of $18.3 million in the same period of 2010 related to settled hedging transactions. Natural gas, NGL and oil sales include $53.9 million of gains in the six months ended June 30, 2011 compared to gains of $19.6 million in the same period of 2010 related to settled hedges. Any ineffectiveness associated with these hedge derivatives is included in derivative fair value income in the accompanying consolidated statements of operations. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. The three months ended June 30, 2011 includes ineffective gains (unrealized and realized) of $7.5 million compared to gains of $265,000 in the same period of 2010. The six months ended June 30, 2011 includes ineffective gains (unrealized and realized) of $9.0 million compared to losses of $341,000 in the same period of 2010.
     Through June 30, 2011, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in derivative fair value income (loss) in the accompanying consolidated statements of operations. During the first three and six months of 2011 or 2010, there were no gains or losses recorded due to the discontinuance of hedge accounting treatment for these derivatives.

14


 

     Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas and oil production. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in derivative fair value income in the accompanying consolidated statements of operations (for additional information see table below).
Derivative Fair Value Income
     The following table presents information about the components of derivative fair value income in the three and six months ended June 30, 2011 and 2010 (in thousands):
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Hedge ineffectiveness — realized
  $ 1,576     $ 5     $ 2,522     $ (352 )
— unrealized
    5,934       260       6,502       11  
Change in fair value of derivatives that do not qualify for hedge accounting(a)
    48,139       (4,409 )     8,103       42,169  
Realized gain on settlements — gas(a) (b)
    3,484       10,690       3,090       7,051  
Realized loss on settlements — oil (a) (b)
    (6,094 )           (8,012 )      
 
                       
Derivative fair value income
  $ 53,039     $ 6,546     $ 12,205     $ 48,879  
 
                       
 
(a)   Derivatives that do not qualify for hedge accounting.
 
(b)   These amounts represent the realized gains or losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category described above called change in fair value of derivatives that do not qualify for hedge accounting.
     The combined fair value of derivatives included in the accompanying consolidated balance sheets as of June 30, 2011 and December 31, 2010 is summarized below (in thousands). As of June 30, 2011 we have conducted commodity derivative activities with ten financial institutions, of which all but one are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. In our accompanying consolidated balance sheets, derivative assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.
                 
    June 30,     December 31,  
    2011     2010  
Derivative assets:
               
Natural gas — collars
  $ 107,258     $ 155,159  
— collars — discontinued operations
          8,195  
— swaps
    4,014        
Crude oil — collars
    (15,830 )      
— call options
    (43,675 )     (31,904 )
NGL — swaps
    13,750        
 
           
 
  $ 65,517     $ 131,450  
 
           
 
               
Derivative liabilities:
               
Natural gas — collars
  $ 3,079     $ 27,032  
— basis swaps
          (352 )
— swaps
    169        
Crude oil — collars
          (12,051 )
— call options
    (7,675 )     (28,393 )
NGL — swaps
           
 
           
 
  $ (4,427 )   $ (13,764 )
 
           

15


 

     The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our accompanying consolidated balance sheets (in thousands):
                                                 
    June 30, 2011     December 31, 2010  
    Assets     (Liabilities)             Assets     (Liabilities)        
                    Net                     Net  
    Carrying     Carrying     Carrying     Carrying     Carrying     Carrying  
    Value     Value     Value     Value     Value     Value  
Derivatives that qualify for cash flow hedge accounting:
                                               
Swaps (1)
  $ 4,184     $     $ 4,184     $     $     $  
Collars(1)
    103,907             103,907       164,933             164,933  
Collars (1) — discontinued operations
                      8,195             8,195  
 
                                   
 
  $ 108,091     $     $ 108,091     $ 173,128     $     $ 173,128  
 
                                   
 
                                               
Derivatives that do not qualify for hedge accounting:
                                               
Swaps (1)
  $ 13,750     $     $ 13,750     $     $     $  
Collars(1)
    6,430       (15,830 )     (9,400 )     17,259       (12,052 )     5,207  
Call options(1)
          (51,351 )     (51,351 )           (60,297 )     (60,297 )
Basis swaps(1)
                            (352 )     (352 )
 
                                   
 
  $ 20,180     $ (67,181 )   $ (47,001 )   $ 17,259     $ (72,701 )   $ (55,442 )
 
                                   
 
(1)   Included in unrealized derivative gain or loss in the accompanying consolidated balance sheets.
     The effects of our cash flow hedges (or those derivatives that qualify for hedge accounting) on accumulated other comprehensive income (loss) included in the accompanying consolidated balance sheets are summarized below (in thousands):
                                                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
                    Realized Gain (Loss)                     Realized Gain (Loss)  
    Change in Hedge     Reclassified from OCI     Change in Hedge     Reclassified from OCI  
    Derivative Fair Value     into Revenue (a)     Derivative Fair Value     into Revenue (a)  
    2011     2010     2011     2010     2011     2010     2011     2010  
Swaps
  $ 4,655     $     $     $     $ 2,115     $     $     $  
Collars
    23,223       (6,887 )     24,285       18,340       22,424       77,930       53,902       19,555  
Collars — discontinued operations
          19                   412       13       8,607        
Income taxes
    (10,454 )     2,611       (9,107 )     (6,969 )     (7,414 )     (29,618 )     (23,441 )     (7,431 )
 
                                               
 
  $ 17,424     $ (4,257 )   $ 15,178     $ 11,371     $ 17,537     $ 48,325     $ 39,068     $ 12,124  
 
                                               
 
(a)   For realized gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGL and oil sales. For realized losses upon contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGL and oil sales.

16


 

     The effects of our non-hedge derivatives (or those derivatives that do not qualify for hedge accounting) and the ineffective portion of our hedge derivatives included in the accompanying consolidated statements of operations are summarized below (in thousands):
                                                 
    Three Months Ended June 30,  
    Gain (Loss) Recognized in     Gain Recognized in Income     Derivative Fair Value  
    Income (Non-hedge Derivatives)     (Ineffective Portion)     (Loss) Income  
    2011     2010     2011     2010     2011     2010  
Swaps
  $ 15,613     $     $     $     $ 15,613     $  
Collars
    6,452       1,483       7,510       265       13,962       1,748  
Call options
    23,464                         23,464        
Basis swaps
          4,798                         4,798  
 
                                   
Total
  $ 45,529     $ 6,281     $ 7,510     $ 265     $ 53,039     $ 6,546  
 
                                   
                                                 
    Six Months Ended June 30,  
    Gain (Loss) Recognized in     Gain Recognized in Income     Derivative Fair Value  
    Income (Non-hedge Derivatives)     (Ineffective Portion)     (Loss) Income  
    2011     2010     2011     2010     2011     2010  
Swaps
  $ 13,750     $     $     $     $ 13,750     $  
Collars
    (1,135 )     48,438       9,024       (341 )     7,889       48,097  
Call options
    (9,391 )                       (9,391 )      
Basis swaps
    (43 )     782                   (43 )     782  
 
                                   
Total
  $ 3,181     $ 49,220     $ 9,024     $ (341 )   $ 12,205     $ 48,879  
 
                                   
(13) FAIR VALUE MEASUREMENTS
     Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
     The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
    Level 1 — Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
    Level 2 — Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
 
    Level 3 — Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

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     Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Fair Values-Recurring
     We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):
                                 
    Fair Value Measurements at June 30, 2011 Using:        
    Quoted Prices in     Significant             Total  
    Active Markets     Other     Significant     Carrying  
    for Identical     Observable     Unobservable     Value as of  
    Assets     Inputs     Inputs     June 30,  
    (Level 1)     (Level 2)     (Level 3)     2011  
Trading securities held in our deferred compensation plans
  $ 52,129     $     $     $ 52,129  
Derivatives – swaps
          17,934             17,934  
– collars
          94,507             94,507  
– call options
          (51,351 )           (51,351 )
     Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using June 30, 2011 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.
     Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in our accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends and mark-to-market gains/losses are included in deferred compensation plan expense in our consolidated statements of operations. For the three months ended June 30, 2011, interest and dividends were $60,000 and mark-to-market was a gain of $5,000. For the three months ended June 30, 2010, interest and dividends were $39,000 and mark-to-market was a gain of $3.2 million. For the six months ended June 30, 2011, interest and dividends were $95,000 and mark-to-market was a gain of $1.3 million. For the six months ended June 30, 2010 interest and dividends were $71,000 and mark-to-market was a gain of $3.8 million. For additional information on the accounting for our deferred compensation plan, see Note 14.
Fair Values-Nonrecurring
     We review our long-lived assets to be held and used, including proved natural gas and oil properties, whenever events or circumstances indicate the carrying value of those assets may not be recoverable. Several long-lived assets held for use were evaluated for impairment during 2010 due to reductions in estimated reserves and natural gas prices. The fair value of our onshore Gulf Coast assets in 2010 was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. Our projected undiscounted cash flows associated with these assets was less than their carrying value and therefore, we recorded an impairment of $6.5 million in 2010 related to our onshore Gulf Coast proved properties.
     The following table presents the value of these assets measured at fair value on a nonrecurring basis (in thousands):
                                 
    Six Months Ended June 30,
    2011   2010
                    Fair    
    Fair Value   Impairment   Value   Impairment
Natural gas and oil properties
  $     $     $ 16,075     $ 6,505  

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Fair Values-Reported
     The following table presents the carrying amounts and the fair values of our financial instruments as of June 30, 2011 and December 31, 2010 (in thousands):
                                 
    June 30, 2011   December 31, 2010
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
Assets:
                               
Commodity swaps, collars, call options and basis swaps
  $ 65,517     $ 65,517     $ 123,255     $ 123,255  
Commodity collars – discontinued operations
                8,195       8,195  
Marketable securities(a)
    52,129       52,129       47,794       47,794  
 
                               
Liabilities:
                               
Commodity swaps, collars, call options and basis swaps
    (4,427 )     (4,427 )     (13,764 )     (13,764 )
Bank credit facility (b)
                (274,000 )     (274,000 )
6.375% senior subordinated notes due 2015 (b)
                (150,000 )     (153,000 )
7.5% senior subordinated notes due 2016 (b)
                (249,683 )     (259,375 )
7.5% senior subordinated notes due 2017 (b)
    (250,000 )     (265,625 )     (250,000 )     (263,438 )
7.25% senior subordinated notes due 2018 (b)
    (250,000 )     (265,000 )     (250,000 )     (263,750 )
8.0% senior subordinated notes due 2019 (b)
    (287,398 )     (325,500 )     (286,853 )     (326,625 )
6.75% senior subordinated notes due 2020 (b)
    (500,000 )     (517,500 )     (500,000 )     (515,625 )
5.75% senior subordinated notes due 2021(b)
    (500,000 )     (491,250 )            
 
(a)   Marketable securities are held in our deferred compensation plans.
 
(b)   The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes.
Concentration of Credit Risk
     Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as deemed necessary to limit risk of loss. Our allowance for uncollectible receivables was $3.8 million at June 30, 2011 and $5.0 million at December 31, 2010. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. As of June 30, 2011, these contracts consist of swaps, collars and call options. This exposure is diversified among major investment grade financial institutions and we have master netting agreements with the counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include ten financial institutions, of which all but one are secured lenders in our bank credit facility. Macquarie Bank Limited is the only counterparty not in our bank group. At June 30, 2011 our net derivative receivable includes a receivable from Macquarie Bank Limited of $6.9 million. Our natural gas and oil properties provide collateral under our credit facility and our derivative exposure. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.
(14)   EMPLOYEE BENEFIT AND EQUITY PLANS
     We have two active equity-based stock compensation plans. Under these plans, incentive and non-qualified stock options, SARs, restricted stock, restricted stock units, phantom stock and various other awards may be issued to employees and directors pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors.

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Equity Awards – SARs/Stock Options
     All awards granted have been issued at prevailing market prices at the time of the grant. Information with respect to stock option/SARs activity is summarized below:
                 
            Weighted  
            Average  
    Shares     Exercise Price  
Outstanding at December 31, 2010
    6,461,839     $ 37.20  
Granted
    841,620       51.15  
Exercised
    (1,507,274 )     27.00  
Expired/forfeited
    (193,940 )     54.31  
 
           
Outstanding at June 30, 2011
    5,602,245     $ 41.44  
 
           
     The weighted average fair value of a SAR to purchase one share of common stock granted during 2011 was $18.21. The fair value of each SAR granted during 2011 was estimated as of the date of grant using the Black-Scholes-Merton option-pricing model based on the following average assumptions: risk-free interest rate of 1.4%; dividend yield of 0.3%; expected volatility of 47% and an expected life of 3.6 years. Of the 5.6 million stock option/SARs outstanding at June 30, 2011, 658,000 are stock options and 4.9 million are SARs.
Equity Awards-Restricted Stock Units
     Beginning in first quarter 2011, the compensation committee began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us. Net shares will be issued to employees as the restricted stock units vest. A summary of the non-vested restricted stock unit awards at June 30, 2011 is presented below:
                 
            Weighted  
            Average  
            Grant Date  
    Shares     Fair Value  
Non-vested restricted stock units outstanding at December 31, 2010
        $  
Granted
    329,399       49.46  
Vested
    (36,995 )     49.22  
Expired/forfeited
    (8,472 )     49.18  
 
           
Non-vested restricted stock units outstanding at June 30, 2011
    283,932     $ 49.50  
 
           
Liability Awards-Restricted Stock
     These restricted stock shares are placed into our deferred compensation plan when granted. During the first six months of 2011, 334,000 shares of restricted stock (or non-vested shares) were issued to certain employees at an average price of $51.10 with a three-year vesting period and 15,500 shares were granted to directors at an average price of $52.35 with immediate vesting. In the first six months of 2010, we issued 385,000 shares of restricted stock as compensation to employees at an average price of $45.97 with a three-year vesting period and 21,000 shares were granted to our directors at an average price of $45.51 with immediate vesting. All restricted stock awards held in our deferred compensation plans are classified as a liability award and remeasured at fair value each reporting period. This mark-to-market is included in deferred compensation plan expense in our accompanying consolidated statements of operations (see additional discussion below). All awards granted have been issued at prevailing market prices at the time of the grant and the vesting of these shares is based upon an employee’s continued employment with us.

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     A summary of the status of our non-vested restricted stock outstanding at June 30, 2011 is presented below:
                 
            Weighted  
            Average Grant  
    Shares     Date Fair Value  
Non-vested restricted stock outstanding at December 31, 2010
    582,751     $ 44.81  
Granted
    349,480       51.16  
Vested
    (213,929 )     46.83  
Forfeited
    (21,176 )     44.87  
 
           
Non-vested restricted stock outstanding at June 30, 2011
    697,126     $ 47.37  
 
           
Deferred Compensation Plan
     Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest such amounts in Range common stock or make other investments at the individual’s discretion. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals either in cash or in Range stock. The liability associated with the vested portion of Range stock is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements 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 in the accompanying consolidated balance sheets. Changes in the market value of the marketable securities are charged or credited to deferred compensation plan expense each quarter. The deferred compensation liability included in our consolidated balance sheets reflects the vested market value of the marketable securities and Range common stock held in the Rabbi Trust. We recorded non-cash, mark-to-market income related to our deferred compensation plan of $5.8 million in the three months ended June 30, 2011 compared to income of $14.1 million in the same period of 2010. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $24.9 million in the six months ended June 30, 2011 compared to income of $19.8 million in the same period of 2010.
(15) SUPPLEMENTAL CASH FLOW INFORMATION
                 
    Six Months Ended  
    June 30,  
    2011     2010  
    (in thousands)  
Non-cash investing and financing activities included:
               
Asset retirement costs capitalized, net
  $ 12,717     $ 864  
Unproved property purchased with stock(a)
  $     $ 20,000  
Net cash provided from operating activities included:
               
Interest paid
  $ 68,002     $ 58,457  
Income taxes paid (refunded)
  $ 308     $ (684 )
 
(a)   Six months ended June 30, 2010 included shares that were issued in January 2010 while the value was accrued and included in costs incurred for the year ended December 31, 2009.

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(16) COMMITMENTS AND CONTINGENCIES
Litigation
     We are involved in various legal actions, claims and other regulatory proceedings arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income or loss in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that the loss is probable and the amount can be reasonably estimated.
Transportation Contracts
     As of June 30, 2011, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):
         
    Transportation  
    Commitments  
2011 (remaining)
  $ 45,315  
2012
    90,361  
2013
    89,768  
2014
    88,826  
2015
    86,361  
Thereafter
    503,940  
 
     
 
  $ 904,571  
 
     
     
(17)   CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION(a)
                 
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Natural gas and oil properties:
               
Properties subject to depletion
  $ 5,326,056     $ 4,742,248  
Unproved properties
    673,609       648,143  
 
           
Total
    5,999,665       5,390,391  
Accumulated depreciation, depletion and amortization
    (1,447,300 )     (1,306,378 )
 
           
Net capitalized costs
  $ 4,552,365     $ 4,084,013  
 
           
 
(a)   Includes capitalized asset retirement costs and associated accumulated amortization.

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(18) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT(a)
                 
    Six Months     Year  
    Ended     Ended  
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Acquisitions:
               
Unproved leasehold
  $     $ 3,697  
Proved properties
          130,767  
Asset retirement obligations
          556  
Acreage purchases
    67,140       151,572  
Development
    476,702       727,720  
Exploration:
               
Drilling
    68,936       50,433  
Expense
    36,513       56,298  
Stock-based compensation expense
    2,266       4,209  
Gas gathering facilities:
               
Development
    11,540       19,627  
 
           
Subtotal
    663,097       1,144,879  
Asset retirement obligations
    12,716       (6,370 )
 
           
Total costs incurred – continuing operations
    675,813       1,138,509  
Discontinued operations
    3,502       73,369  
 
           
Total costs incurred
  $ 679,315     $ 1,211,878  
 
           
 
(a)   Includes costs incurred whether capitalized or expensed and include our Barnett operations.
     
(19)   OFFICE CLOSING AND EXIT ACTIVITIES
     In February 2010, we entered into an agreement to sell our natural gas properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder of the sale in June 2010. The first quarter 2010 includes $5.1 million accrued severance costs, which is reflected in termination costs in the accompanying consolidated statements of operations. As part of their severance agreement, our Ohio employees’ vesting of SARs and restricted stock grants was accelerated, increasing termination costs for stock compensation expense in first quarter 2010 by approximately $2.8 million.
     The following table details our exit activities, which are included in accrued liabilities in the accompanying consolidated balance sheets as of June 30, 2011 and December 31, 2010 (in thousands):
                 
    Six Months     Year  
    Ended     Ended  
    June 30,     December 31,  
    2011     2010  
    (in thousands)  
Balance at beginning of period
  $ 1,092     $ 1,568  
Accrued one-time termination costs
          5,138  
Office lease
    (117 )     514  
Payments
    (742 )     (6,128 )
 
           
Balance at end of period
  $ 233     $ 1,092  
 
           

23


 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. For additional risk factors affecting our business, see Item 1A. Risk Factors as filed with our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on March 1, 2011.
Critical Accounting Estimates and Policies
     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. These policies and estimates are described in our Current Report on Form 8-K for the year ended December 31, 2010 filed with the SEC on May 6, 2011. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: accounting for natural gas, NGL and oil revenue, natural gas and oil properties, stock-based compensation, derivative financial instruments, asset retirement obligations and deferred income taxes.
Market Conditions
     Prices for various quantities of natural gas, natural gas liquids (“NGLs”) and oil that we produce significantly impact our revenues and cash flows. Commodity prices can fluctuate widely. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil for the three months and six months ended June 30, 2011 and 2010.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Average NYMEX prices(a)
                               
Natural gas (per mcf)
  $ 4.36     $ 4.08     $ 4.25     $ 4.71  
Oil (per bbl)
    102.33       77.71       98.77       78.28  
 
(a)   Based on average of bid week prompt month prices.
Consolidated Results of Operations
Overview
     We are an independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties, mostly in the Appalachia and Southwest regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to economically find, develop, acquire and produce natural gas and oil reserves. We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital program. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in Fort Worth, Texas. Discontinued operations consist of our Barnett Shale properties which were sold in second quarter 2011. Unless otherwise indicated, the information included herein relates to our continuing operations.

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     During the first six months of 2011, we achieved the following financial and operating results:
    achieved 29% year-over-year production growth;
 
    daily production now exceeds 455.0 mmcfe per day;
 
    natural gas, NGL and oil sales increased 34% from six months of 2010;
 
    reduced our DD&A rate 12% from six months 2010;
 
    year-over-year direct operating expense per mcfe increased 1% while production and ad valorem tax expense per mcfe declined 11% and general and administrative expense per mcfe declined 11%;
 
    sold substantially all of our Barnett Shale properties for gross proceeds of $877.0 million, including assumed hedges;
 
    entered into additional commodity derivative contracts for 2011, 2012 and 2013;
 
    renewed our bank credit facility with a borrowing base of $2.0 billion;
 
    issued $500.0 million of new 5.75% senior subordinated notes, at par; and
 
    used the proceeds from the issuance of $500.0 million of new 5.75% senior subordinated notes to retire all $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and all $250.0 million principal amount of our 7.5% senior subordinated notes due 2016.
Second Quarter Highlights
     Total revenues increased $115.5 million, or 60% for second quarter 2011 over the same period of 2010. The increase includes a $83.5 million increase in natural gas, NGL and oil sales and an increase in derivative fair value income of $46.5 million partially offset by lower gain on sale of assets of $11.8 million. Natural gas, NGL and oil sales vary due to changes in volumes of production sold and realized commodity prices. Realized prices increased from the same period of the prior year, along with an increase in production, including a 73% increase in NGL production primarily due to increased liquids-rich production in our Appalachia area. For second quarter 2011, production increased 33% from the same period of the prior year while realized prices (including all derivative settlements) increased 5%. In second quarter 2011, we completed the sale of most of our Barnett Shale properties for cash gross proceeds of $877.0 million, including assumed hedges, resulting in a pretax gain of $3.8 million. See also Note 4 and 5 for specific information on the sale of these assets including their treatment as discontinued operations.
     In May 2011, we issued, at par, $500.0 million of 5.75% senior subordinated notes due 2021. The net proceeds were used to repurchase $150.0 million of our 6.375% senior subordinated notes due 2015 (“6.375% Notes”) and $250.0 million of our 7.5% senior subordinated notes due 2016 (“7.5% Notes”) and for general working capital purposes. On May 24, 2011, we commenced cash tender offers to purchase the entire outstanding principal amount of each of the 6.375% Notes and the 7.5% Notes. Upon expiration of the tender offers in May 2011, we accepted for purchase $108.9 million in principal of the 6.375% Notes at 102.375% of par and $198.8 million in principal of the 7.5% Notes at 104.0% of par. We called the remaining 6.375% Notes and 7.5% Notes, repurchasing all of the remaining outstanding 6.375% Notes at 102.125% of par on June 24, 2011 and repurchased all of the remaining outstanding 7.5% Notes at 103.75% of par on June 24, 2011. During second quarter 2011, we recognized a $18.6 million loss on extinguishment of debt in the accompanying statements of operations.
     We continue to believe natural gas, NGL and oil prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new regulations, new technology, the level of natural gas and oil production in North America and worldwide political conditions in natural gas and oil producing regions. Although we have entered into derivative contracts covering a portion of our production volumes for 2011, 2012 and 2013, a sustained lower price environment would result in lower realized prices for unprotected volumes and reduce the prices we can enter into derivative contracts for additional volumes in the future.
Natural Gas, NGL and Oil Sales Production and Realized Price Calculation
     Our natural gas, NGL and oil sales vary from quarter to quarter as a result of changes in realized commodity prices and volumes of production sold. Hedges included in natural gas, NGL and oil sales reflect settlements on those derivatives that qualify for hedge accounting. The cash settlement of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying consolidated statements of operations. The following table summarizes the primary components of natural gas, NGL and oil sales for the three months and six months ended June 30, 2011 and 2010 (in thousands):

25


 

                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Gas wellhead
  $ 123,300     $ 95,257     $ 28,043       29 %   $ 229,583     $ 218,527     $ 11,056       5 %
Gas hedges realized
    24,285       18,317       5,968       33 %     53,901       19,532       34,369       176 %
 
                                                   
Total gas sales
    147,585       113,574       34,011       30 %     283,484       238,059       45,425       19 %
 
                                                   
 
                                                               
NGL’s
    62,598       27,402       35,196       128 %     117,073       55,426       61,647       111 %
 
                                                   
 
                                                               
Oil wellhead
    46,504       32,154       14,350       45 %     83,011       67,318       15,693       23 %
Oil hedges realized
          23       (23 )     100 %           23       (23 )     100 %
 
                                                   
Total oil sales
    46,504       32,177       14,327       45 %     83,011       67,341       15,760       23 %
 
                                                   
 
                                                               
Combined wellhead
    232,402       154,813       77,589       50 %     429,667       341,271       88,396       26 %
Combined hedges realized
    24,285       18,340       5,945       32 %     53,901       19,555       34,346       176 %
 
                                                   
Total natural gas, NGL and oil sales
  $ 256,687     $ 173,153     $ 83,534       48 %   $ 483,568     $ 360,826     $ 122,742       34 %
 
                                                   
     Our production continues to grow through continued drilling success as we place new wells into production, partially offset by the natural decline of our wells and asset sales. For second quarter 2011, total production volumes, when compared to the same period of the prior year, increased 48% in our Appalachia area and 3% in our Southwest area. For second quarter 2011, NGL production increased 73% from the same period of the prior year primarily due to increased liquids-rich gas production in our Appalachia area along with an increase in processing capacity in the region. For the six months ended June 30, 2011, our production volumes as compared to the same period of the prior year, increased 44% in our Appalachia area and increased 2% in our Southwest area. Our production for the three months and six months ended June 30, 2011 and 2010 is shown below:
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Production(a):
                                                               
Natural gas (mcf)
    32,811,471       25,426,232       7,385,239       29 %     62,616,994       49,798,399       12,818,595       26 %
NGLs (bbls)
    1,236,502       715,725       520,777       73 %     2,368,067       1,339,199       1,028,868       77 %
Crude oil (bbls)
    502,962       474,557       28,405       6 %     939,094       979,658       (40,564 )     (4 %)
Total (mcfe)(b)
    43,248,255       32,567,924       10,680,331       33 %     82,459,960       63,711,541       18,748,419       29 %
 
                                                               
Average daily production(a):
                                                               
Natural gas (mcf)
    360,566       279,409       81,157       29 %     345,950       275,129       70,821       26 %
NGLs (bbls)
    13,588       7,865       5,723       73 %     13,083       7,399       5,684       77 %
Crude oil (bbls)
    5,527       5,215       312       6 %     5,188       5,412       (224 )     (4 %)
Total (mcfe)(b)
    475,256       357,889       117,367       33 %     455,580       351,997       103,583       29 %
 
(a)   Represents volumes sold regardless of when produced.
 
(b)   NGLs and oil are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.
     Our average realized price (including all derivative settlements) received was $5.91 per mcfe in second quarter 2011 compared to $5.65 per mcfe in the same period of the prior year. Our average realized price (including all derivative settlements) received was $5.84 per mcfe in the six months ended June 30, 2011 compared to $5.77 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlements for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months and six months ended June 30, 2011 and 2010 are shown below:

26


 

                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Average sales prices (wellhead):
                               
Natural gas (per mcf)
  $ 3.76     $ 3.75     $ 3.67     $ 4.39  
NGLs (per bbl)
    50.62       38.29       49.44       41.39  
Crude oil (per bbl)
    92.46       67.76       88.40       68.72  
Total (per mcfe)(a)
    5.37       4.75       5.21       5.36  
 
                               
Average realized price (including derivatives that qualify for hedge accounting):
                               
Natural gas (per mcf)
  $ 4.50     $ 4.47     $ 4.53     $ 4.78  
NGLs (per bbl)
    50.62       38.29       49.44       41.39  
Crude oil (per bbl)
    92.46       67.80       88.39       68.74  
Total (per mcfe)(a)
    5.94       5.32       5.86       5.66  
 
                               
Average realized price (including all derivative settlements):
                               
Natural gas (per mcf)
  $ 4.65     $ 4.89     $ 4.62     $ 4.91  
NGLs (per bbl)
    50.62       38.29       49.44       41.39  
Crude oil (per bbl)
    80.34       67.81       79.86       68.72  
Total (per mcfe)(a)
    5.91       5.65       5.84       5.77  
 
(a)   NGLs and oil are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.
     Derivative fair value income was $53.0 million in second quarter 2011 compared to $6.5 million in the same period of 2010. Derivative fair value income was $12.2 million in the six months ended June 30, 2011 compared to $48.9 million in the same period of 2010. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income in the accompanying consolidated statements of operations. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from non-hedge derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying consolidated balance sheets. Hedge ineffectiveness, also included in this statement of operations category, is associated with our hedging contracts that qualify for hedge accounting.
     The following table presents information about the components of derivative fair value income for the three months and six months ended June 30, 2011 and 2010 (in thousands):
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Hedge ineffectiveness — realized(c)
  $ 1,576     $ 5     $ 2,522     $ (352 )
— unrealized(a)
    5,934       260       6,502       11  
Change in fair value of derivatives that do not qualify for hedge accounting(a)
    48,139       (4,409 )     8,103       42,169  
Realized gain on settlements — gas(b)(c)
    3,484       10,690       3,090       7,051  
Realized loss on settlements — oil(b)(c)
    (6,094 )           (8,012 )      
 
                       
Derivative fair value income
  $ 53,039     $ 6,546     $ 12,205     $ 48,879  
 
                       
 
(a)   These amounts are unrealized and are not included in average sales price calculations.
 
(b)   These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.
 
(c)   These settlements are included in average realized price calculations (average realized price including all derivative settlements).

27


 

     (Loss) gain on the sale of assets for second quarter 2011 decreased $11.8 million from the same period of the prior year. In the three months ended June 30, 2011, we recorded a loss of $1.7 million related to the sale of certain derivatives included with the sale of our Barnett properties. In the three months ended June 30, 2010, we closed the remainder of the sale of our properties in Ohio and recorded a gain of $10.4 million. For the six months ended June 30, 2010, we recorded a gain of $77.4 million from the sale of our Ohio properties and received proceeds of $323.0 million.
     Other income (loss) for second quarter 2011 was a loss of $435,000 compared to a gain of $637,000 in the same period of 2010. Second quarter 2011 includes loss from equity method investments of $1.0 million. The second quarter of 2010 includes income from equity method investments of $636,000. Other income (loss) for the six months ended June 30, 2011 increased from a loss of $938,000 in 2010 to income of $642,000 in 2011. The six months ended June 30, 2011 includes various lawsuit proceeds and refunds partially offset by a loss from equity method investments of $759,000. The six months ended June 30, 2010 includes a loss from equity method investments of $985,000.
     We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about these expenses on a per mcfe basis for the three months and the six months ended June 30, 2011 and 2010:
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Direct operating expense
  $ 0.66     $ 0.65     $ 0.01       2 %   $ 0.69     $ 0.68     $ 0.01       1 %
Production and ad valorem tax expense
    0.17       0.17             %     0.17       0.19       (0.02 )     (11 %)
General and administrative expense
    0.90       1.10       (0.20 )     (18 %)     0.89       1.00       (0.11 )     (11 %)
Interest expense
    0.73       0.65       0.08       12 %     0.68       0.66       0.02       3 %
Depletion, depreciation and amortization expense
    1.81       2.08       (0.27 )     (13 %)     1.83       2.08       (0.25 )     (12 %)
     Direct operating expense increased $7.3 million in second quarter 2011 to $28.5 million. We experience increases in operating expenses as we add new wells and maintain production from existing properties. We incurred $596,000 ($0.01 per mcfe) of workover costs in second quarter 2011 versus $1.0 million ($0.03 per mcfe) in 2010. On a per mcfe basis, direct operating expenses for second quarter 2011 increased $0.01, or 2%, from the same period of 2010 with the increase primarily due to higher equipment rental ($0.03) and higher water hauling and disposal costs ($0.04 per mcfe) somewhat offset by lower workover costs ($0.02 per mcfe) and lower well services costs ($0.03 per mcfe).
     Direct operating expense increased $14.2 million in the first six months 2011 to $57.2 million. We incurred $987,000 ($0.01 per mcfe) of workover costs in the first six months of 2011 compared to $1.8 million ($0.03 per mcfe) in the same period of 2010. On a per mcfe basis, direct operating expense increased $0.01 or 1% from the same period of the prior year with the increase consisting primarily of higher water disposal costs ($0.05 per mcfe) and higher overall well service costs somewhat offset by lower workover costs ($0.02 per mcfe) and the impact of the sale of certain higher operating cost assets during 2010. In the future, we expect to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operating costs relative to our other operating areas. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants.
     The following table summarizes direct operating expenses per mcfe for the three months and six months ended June 30, 2011 and 2010:
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Lease operating expense
  $ 0.64     $ 0.60     $ 0.04       7 %   $ 0.67     $ 0.64     $ 0.03       5 %
Workovers
    0.01       0.03       (0.02 )     (67 %)     0.01       0.03       (0.02 )     (67 %)
Stock-based compensation (non-cash)
    0.01       0.02       (0.01 )     (50 %)     0.01       0.01             %
 
                                                   
Total direct operating expenses
  $ 0.66     $ 0.65     $ 0.01       2 %   $ 0.69     $ 0.68     $ 0.01       1 %
 
                                                   

28


 

     Production and ad valorem taxes are paid based on market prices and not hedged prices. For second quarter 2011, these taxes increased $1.9 million or 33% from the same period of the prior year with higher prices partially offset by an increase in production volumes not subject to production taxes. On a per mcfe basis, production and ad valorem taxes per mcfe remained the same at $0.17 for the three months ended June 2011 and 2010. For the first six months of 2011, these taxes increased $2.2 million or 18% from the same period of the prior year due to a decrease in the number of wells receiving high cost tax credits and higher NGL production volumes subject to production taxes which was partially offset by an increase in production volumes not subject to production taxes and lower prices. On a per mcfe basis, production and ad valorem taxes decreased to $0.17 in the first six months of 2011 compared to $0.19 in the same period of 2010.
     General and administrative expense for second quarter 2011 increased $3.3 million or 9% from the same period of the prior year due primarily to higher community relations costs ($1.1 million), higher stock-based compensation ($729,000), higher legal costs ($1.0 million) and higher office expenses, including information technology. General and administrative expense for the first six months of 2011 increased $9.1 million or 14% from the same period of the prior year primarily due to higher community relations costs ($2.5 million), higher stock-based compensation ($413,000), higher salaries and benefits ($2.3 million), higher legal fees ($2.7 million) and higher office expenses, including information technology. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants. The following table summarizes general and administrative expenses per mcfe for the three months and the six months ended June 30, 2011 and 2010:
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
General and administrative
  $ 0.63     $ 0.77     $ (0.14 )     (18 %)   $ 0.66     $ 0.71     $ (0.05 )     (7 %)
Stock-based compensation (non-cash)
    0.27       0.33       (0.06 )     (18 %)     0.23       0.29       (0.06 )     (21 %)
 
                                               
Total general and administrative expenses
  $ 0.90     $ 1.10     $ (0.20 )     (18 %)   $ 0.89     $ 1.00     $ (0.11 )     (11 %)
 
                                                   
     Interest expense for second quarter 2011 increased $10.1 million from the same period of the prior year due to the refinancing of certain debt from floating to higher fixed rates and higher overall debt balances. In May 2011, we issued $500.0 million of new 5.75% senior subordinated notes due 2021, which added $2.9 million of interest costs in second quarter 2011. The proceeds from the issuance were used to retire our 6.375% senior subordinated notes due 2015 and retire our 7.5% senior subordinated notes due 2016 and for general corporate purposes, in order to better match the maturities of our debt with the life of our properties. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $8.4 million of interest costs in second quarter 2011. The proceeds from the issuance were used to retire our 7.375% senior subordinated notes due 2013 and to lower our floating interest rate bank debt, which better matches the maturities of our debt with the life of our properties and gives us greater liquidity for the near term. Average debt outstanding on the bank credit facility for second quarter 2011 was $171.5 million compared to $421.1 million for the same period of the prior year and the weighted average interest rate was 2.0% in second quarter 2011 compared to 2.2% in the same period of the prior year.
     Interest expense for the six months increased $14.0 million from the same period of the prior year due to the refinancing of certain debt from floating to higher fixed rates and higher overall debt balances. In May 2011, we issued $500.0 million of 5.75% senior subordinated notes due 2021, which added $2.9 million of interest costs in the first six months of 2011. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $16.9 million of interest costs in the first six months of 2011. Average debt outstanding on the credit facility for the first six months 2011 was $296.3 million compared to $390.4 million for the same period of the prior year and the weighted average interest rate was 2.2% in both the six months periods ending June 30, 2011 and 2010.
     Depletion, depreciation and amortization (“DD&A”) increased $10.5 million, or 15%, to $78.3 million in second quarter 2011. The increase was due to a 33% increase in production partially offset by a 12% decrease in depletion rates. On a per mcfe basis, DD&A decreased from $2.08 in second quarter 2010 to $1.81 in second quarter 2011. In the first six months of 2011, DD&A increased $17.9 million with a 29% increase in production partially offset by a 10% decrease in depletion rates. Depletion rates are declining due to our lower finding and development costs and the mix of our production. The following table summarizes DD&A expense per mcfe for the three months and the six months ended June 30, 2011 and 2010:

29


 

                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Depletion and amortization
  $ 1.70     $ 1.93     $ (0.23 )     (12 %)   $ 1.71     $ 1.91     $ (0.20 )     (10 %)
Depreciation
    0.08       0.11       (0.03 )     (27 %)     0.09       0.13       (0.04 )     (31 %)
Accretion and other
    0.03       0.04       (0.01 )     (25 %)     0.03       0.04       (0.01 )     (25 %)
 
                                                   
Total DD&A expense
  $ 1.81     $ 2.08     $ (0.27 )     (13 %)   $ 1.83     $ 2.08     $ (0.25 )     (12 %)
 
                                                   
     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties, termination costs, deferred compensation plan expenses and impairment of proved properties. In the three months ended June 30, 2011 and 2010, stock-based compensation represents the amortization of restricted stock grants, restricted stock units and expenses related to SAR grants. In second quarter 2011, stock-based compensation is a component of direct operating expense ($643,000), exploration expense ($937,000) and general and administrative expense ($11.5 million) for a total of $13.4 million. In second quarter 2010, stock-based compensation was a component of direct operating expense ($563,000), exploration expense ($1.1 million) and general and administrative expense ($10.7 million) for a total of $12.7 million. In the six months ended June 30, 2011, stock-based compensation is a component of direct operating expense ($953,000), exploration expense ($2.3 million) and general and administrative expense ($19.0 million) for a total of $22.9 million. In the six months ended June 30, 2010, stock-based compensation is a component of direct operating expense ($925,000), exploration expense ($2.2 million) and general and administrative expense ($18.6 million) for a total of $22.4 million.
     Exploration expense decreased $2.8 million in second quarter 2011 and increased $10.2 million in the first six months of 2011 from the same periods of the prior year. The three months ended June 30, 2011 includes higher seismic costs more than offset by lower delay rental costs. The six months ended June 30, 2011 includes higher seismic and personnel costs partially offset by lower delay rental costs. The delay rental payments, or costs to defer the commencement of drilling, are primarily attributed to our Marcellus Shale operations. The following table details our exploration-related expenses for the three months and six months ended June 30, 2011 and 2010 (in thousands):
                                                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2011     2010     Change     %     2011     2010     Change     %  
Dry hole expense
  $ (3 )   $     $ (3 )     %   $ 7     $     $ 7       %
Seismic
    4,365       833       3,532       424 %     17,537       8,046       9,491       118 %
Personnel expense
    3,150       2,910       240       8 %     7,176       5,640       1,536       27 %
Stock-based compensation expense
    937       1,069       (132 )     (12 %)     2,266       2,205       61       3 %
Delay rentals and other
    3,143       9,608       (6,465 )     (67 %)     11,793       12,668       (875 )     (7 %)
 
                                                   
Total exploration expense
  $ 11,592     $ 14,420     $ (2,828 )     (20 %)   $ 38,779     $ 28,559     $ 10,220       36 %
 
                                                   
     Abandonment and impairment of unproved properties expense was $18.9 million during the three months ended June 30, 2011 compared to $9.7 million during the same period of 2010. Abandonment and impairment of unproved properties was $35.4 million in the six months ended June 30, 2011 compared to $16.3 million in the same period of the prior year. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. The increase from the prior year is primarily due to increasing expirations in our Marcellus Shale area.
     Termination costs in the first six months of 2010 includes severance costs of $5.1 million related to the sale of our properties in Ohio and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel.
     Deferred compensation plan expense was income of $5.8 million in second quarter 2011 compared to income of $14.1 million in the same period of the prior year. This non-cash expense relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in the deferred compensation plan. Our deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense in the accompanying

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statements of operations. Our stock price decreased from $58.46 at March 31, 2011 to $55.50 at June 30, 2011. During the same period in the prior year, our stock price decreased from $46.87 at March 31, 2010 to $40.15 at June 30, 2010. Deferred compensation plan expense was $24.9 million in the six months ended June 30, 2011 compared to income of $19.8 million in the same period of the prior year. Our stock price increased from $44.98 at December 31, 2010 to $55.50 at June 30, 2011. During the same six month period of the prior year our stock price decreased from $49.85 at December 31, 2009 to $40.15 at June 30, 2010.
     Loss on extinguishment of debt for the second quarter and the six months ended June 30, 2011 was $18.6 million. In May and June 2011, we purchased or redeemed our 6.375% senior subordinated notes due 2015 at a price equal to 102.31% and we purchased or redeemed our 7.5% senior subordinated notes due 2016 at a price equal to 103.95%. We recorded a loss on extinguishment of debt of $18.6 million which includes a call premium and other consideration of $13.3 million and expensing of related deferred financing costs on the repurchased debt.
     Impairment of proved properties in the first six months of 2010 of $6.5 million was recognized due to declining gas prices and is related to a portion of our onshore Gulf Coast properties. Our estimated fair value of producing properties is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flow were based on the latest available proved reserves and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices, at the time of the impairment.
     Income tax expense for second quarter 2011 increased to $32.7 million from $11.8 million in second quarter 2010, reflecting a 167% increase in continuing income from operations before taxes compared to the same period of 2010. Second quarter 2011 provided for tax expense at an effective rate of 41.6% compared to tax expense at an effective rate of 40.0% in the same period of 2010. Income tax expense for the first six months 2011 decreased to $12.8 million from $60.8 million in the first six months 2010, reflecting an 84% decrease in continuing income from operations before taxes. The first six months 2011 provided for tax expense at an effective rate of 50.9% compared to an effective tax rate of 38.9% in the same period of 2010. We expect our effective tax rate to be approximately 40% for the remainder of 2011. Our overall effective tax rate is higher than the statutory rate of 35% due to state income taxes, valuation allowances and other permanent differences.
     Discontinued operations for the second quarter 2011 includes the operating results of our Barnett properties for April 2011 and a pre-tax gain of $3.8 million recorded on the sale. Discontinued operations for the first six months ended 2011 includes the operating results of our Barnett properties through the date of the sale and a pre-tax gain of $3.8 million recorded on the sale. See also Note 4 and 5 for specific information regarding our discontinued operations.
Capital Resources, Liquidity and Financial Condition
Capital Resources
     Our primary capital resources are net cash provided by operating activities, proceeds from the sale of assets and proceeds from financing activities. If internal cash flow and cash on hand do not meet our expectations, we may reduce our level of capital expenditures, and/or fund a portion of our capital expenditures under our bank credit facility, issue debt or equity securities and/or sell assets.
Cash Flow
     Cash flows from operating activities primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operating activities also are impacted by changes in working capital. We sell substantially all of our natural gas, NGL and oil production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future natural gas and oil production for the next 12 to 36 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs can be funded by borrowing under the credit facility. As of June 30, 2011, we have entered into derivative agreements covering 75.1 Bcfe for 2011, 120.7 Bcfe for 2012 and 58.4 Bcfe for 2013.
     Net cash provided from continuing operations for the six months ended June 30, 2011 was $276.8 million compared to $208.7 million in the six months ended June 30, 2010. Cash flow from continuing operations for the first six months of 2011 was higher than the same period of the prior year, as higher production from development activity, higher realized prices and a $15.0 million equity method investment distribution was partially offset by higher operating costs. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) in the six months ended June 30, 2011 was a decrease of $8.1 million compared to an increase of $8.2 million in the same period of the prior year.

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     During second quarter 2011, we completed the sale of primarily all of our Barnett properties for gross cash proceeds of $877.0 million, including assumed hedges and before post-closing adjustments, resulting in a pretax gain of $3.8 million. The net cash proceeds from the sale of these assets was determined in accordance with the purchase and sale agreement which provides for certain customary adjustments for matters occurring after the effective date of the sale, such as capital contributions and working capital adjustments. Differences between actual working capital amounts and estimated working capital amounts recorded as of June 30, 2011 will be recorded as income or loss from discontinued operations in future periods.
     Net cash used in financing activities for the six months ended June 30, 2011 was $272.8 million compared to net cash provided from financing activities of $135.2 million in the same period of 2010. During the six months ended June 30, 2011, we:
    borrowed $490.8 million and repaid $764.8 million under our bank credit facility, ending the period with no outstanding borrowings under our credit facility;
 
    issued $500.0 million principal amount of 5.75% senior subordinated notes due 2021, at par;
 
    purchased or redeemed $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 at a redemption price of 102.31% and purchased or redeemed $250.0 million principal amount of our 7.5% senior subordinated notes due 2016 at a redemption price of 103.9%;
 
    spent $21.7 million related to debt issuance costs; and
 
    recorded a decrease of $58.3 million in cash overdrafts.
     During the six months ended June 30, 2010, we:
    borrowed $371.0 million and repaid $220.0 million under our bank credit facility, ending the period with a $30.0 million higher bank credit facility balance.
Credit Arrangements
     On June 30, 2011, the bank credit facility had a $2.0 billion borrowing base, a $1.5 billion facility amount and we had no outstanding borrowings. The borrowing base represents an amount approved by the bank group that can be borrowed based on our assets, while our $1.5 billion facility amount is the amount we have requested that the banks commit to fund pursuant to the credit agreement. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Remaining credit availability was $1.5 billion on July 22, 2011. Our bank group is comprised of twenty-seven commercial banks with no one bank holding more than 7.0% of the bank credit facility. We believe our large number of banks and relatively low hold levels allow for significant lending capacity should we elect to increase our $1.5 billion commitment up to the $2.0 billion borrowing base and also allow for flexibility should there be additional consolidation within the banking sector.
     Our bank credit facility and our indentures governing our senior subordinated notes all contain covenants that, among other things, limit our ability to pay dividends, incur additional indebtedness, sell assets, enter into hedging contracts, change the nature of our business or operations, merge or consolidate or make certain investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with these covenants at June 30, 2011. See Note 9 to the accompanying consolidated financial statements for additional information.
     In May 2011, we issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021 (“5.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 5.75% Notes were issued at par. Interest on the 5.75% Notes is payable semi-annually in June and December and is guaranteed by substantially all of our subsidiaries. We may redeem the 5.75% Notes, in whole or in part, at any time on or after June 1, 2016, at redemption prices of 102.875% of the principal amount as of June 1, 2016 declining to 100.0% on June 1, 2019 and thereafter. Before June 2014, we may redeem up to 35% of the original aggregate principal amount of the 5.75% Notes at a redemption price equal to 105.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.75% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. On closing, we used $112.9 million of the proceeds to redeem our 6.375% senior subordinated notes due 2015 and $207.1 million to redeem our 7.5% senior subordinated notes due 2016 as part of the tender offer described below.
     On May 11, 2011, we commenced cash tender offers to purchase the entire outstanding $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and $250.0 million principal amount of our 7.5% senior subordinated notes due 2016. On May 25, 2011, after the expiration of the tender offers, we accepted for purchase $108.9 million in principal of the 2015 notes at 102.375% of par and $198.8 million in principal of the 2016 notes for 104.00% of par. We

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called the remaining 2015 and 2016 notes, redeeming all of the remaining outstanding 2015 notes ($41.1 million) at 102.125% of par on June 24, 2011 and redeeming all of the remaining outstanding 2016 notes ($51.2 million) at 103.75% of par on June 24, 2011. During the second quarter 2011, we recognized an $18.6 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.
     In June 2009, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability, subject to market conditions, to issue and sell an indeterminate amount of various types of registered debt and equity securities.
     As we pursue our strategy, we may utilize various financing sources, including, to the extent available, fixed and floating rate debt, or common stock. We may also issue securities in exchange for oil and gas properties.
Liquidity
     Our principal sources of short-term liquidity are cash on hand and unused borrowing capacity under our bank credit facility. As of June 30, 2011, we had no outstanding borrowings under our credit facility and we were in compliance with all of its debt covenants. After adjusting for $13.9 million of undrawn and outstanding letters of credit, we had approximately $1.5 billion of unused borrowing capacity as of June 30, 2011.
     If internal cash flow and cash on hand do not meet our expectations, we may reduce our level of capital expenditures, and/or fund a portion of our capital expenditures using borrowings under our bank credit facility, issue debt or equity securities or receive cash from other sources, such as asset sales. We cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although we expect that internal operating cash flows, cash on hand and borrowing capacity under our bank credit facility will be adequate to fund capital expenditures and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet our future needs. For instance, the amount that we may borrow under the bank credit facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.
     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our outstanding debt and credit ratings by rating agencies.
Capital Commitments
     Our primary needs for cash are for capital expenditures on natural gas and oil assets, payment of contractual obligations, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally generated cash flow, proceeds from the disposition of assets or external financing sources. We expect we will be able to fund our needs for cash (excluding acquisitions) with internally-generated cash flows, cash on hand and liquidity under our credit facility, although no assurances can be given that such funding will be adequate to meet our future needs. We generally strive to limit our capital expenditures to internally-generated cash flow plus proceeds from asset sales. We establish a capital budget at the beginning of each calendar year. Our 2011 capital budget (excluding acquisitions) now stands at $1.38 billion and focuses on projects we believe will generate and lay the foundation for economic, long-term production growth.
Investing Activities
     Net cash used in investing activities of continuing operations for the six months ended June 30, 2011 was $590.0 million compared to $202.5 million in the same period of 2010. During the six months ended June 30, 2011, we:
    spent $535.3 million on natural gas and oil property additions;
 
    spent $73.1 million on acreage primarily in the Marcellus Shale; and
 
    received proceeds of $23.4 million primarily from the sale of a low pressure pipeline.
     During the six months ended June 30, 2010, we:
    spent $322.4 million on natural gas and oil property additions;
 
    spent $187.2 million on acreage primarily in the Marcellus Shale; and
 
    received proceeds of $318.6 million primarily from the sale of our Ohio oil and gas properties.

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Dividends
     On June 30, 2011, the Board of Directors declared a dividend of four cents per share ($6.4 million) on our common stock, which was paid on June 30, 2011 to stockholders of record at the close of business on June 17, 2011. Future dividends are at the discretion of the Board and, if declared, the Board may change the current dividend amount based on our liquidity and capital resources.
Contractual Obligations
     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportations commitments and other purchase obligations. The table below summarizes our significant contractual obligations as of June 30, 2011 (in thousands).
                                                 
    Payment due by period  
    Remaining                     2014              
    2011     2012     2013     and 2015     Thereafter     Total  
7.5% senior subordinated notes due 2017
  $     $     $     $     $ 250,000     $ 250,000  
7.25% senior subordinated notes due 2018
                            250,000       250,000  
8.0% senior subordinated notes due 2019
                            300,000       300,000  
6.75% senior subordinated notes due 2020
                            500,000       500,000  
5.75% senior subordinated notes due 2021
                            500,000       500,000  
Operating leases
    5,762       12,863       10,041       18,890       28,574       76,130  
Drilling rig commitments
    32,163       52,305       14,673       896             100,037  
Transportation commitments
    45,315       90,361       89,768       175,187       503,940       904,571  
Other purchase obligations
    27,013       49,026       3,386       28             79,453  
Derivative obligations (a)
          6,384       (1,957 )                 4,427  
Asset retirement obligation liability (b)
    4,020       8,801       1,137       4,168       56,240       74,366  
 
                                   
Total contractual obligations (c)
  $ 114,273     $ 219,740     $ 117,048     $ 199,169     $ 2,388,754     $ 3,038,984  
 
                                   
 
(a)   Derivative obligations represent net open derivative contracts valued as of June 30, 2011. While such payments will be funded by higher prices received from the sale of our production, production receipts may be received after our payments to counterparties, which can result in borrowings under our bank credit facility.
 
(b)   The ultimate settlement and timing cannot be precisely determined in advance.
 
(c)   This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.
Debt Ratings
     We receive debt credit ratings from two of the major ratings agencies, which are subject to regular reviews. We believe that each of the rating agencies consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in our debt ratings could negatively impact our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.
Book Capitalization
     Our net book capitalization at June 30, 2011 was $3.7 billion, consisting of $288.8 million of cash and cash equivalents, debt of $1.8 billion and stockholder’s equity of $2.2 billion. Our net debt to net book capitalization was 40.0 percent at June 30, 2011 and 46.9 percent at December 31, 2010.
Capital Requirements
     We currently estimate our 2011 capital spending will approximate $1.38 billion (excluding acquisitions) and based on current projections is expected to be funded with internal cash flow, property sales and our bank credit facility. Acreage purchases during the first six months include $56.7 million of purchases in the Marcellus Shale, which were funded with borrowings under our credit facility. For the six months ended June 30, 2011, $587.3 million of our development and exploration spending was funded with internal cash flow, borrowings under our bank credit facility and asset sales. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may choose to sell assets, issue subordinated notes or other debt securities, or issue additional shares of stock to fund capital expenditures or acquisitions, extend maturities or repay debt.

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Other Contingencies
     We are involved in various legal actions, claims and other regulatory proceedings arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our liquidity or consolidated financial position. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income or loss in the period in which the ruling occurs.
Hedging — Natural Gas and Oil Prices
     We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. Historically, these contracts consisted of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. In light of current worldwide economic uncertainties, we have employed a strategy to hedge a portion of our production looking out 12 to 36 months from each quarter. At June 30, 2011, we had open swap contracts covering 25.6 Bcf of natural gas at prices averaging $5.00 and 3.1 million barrels of NGLs (the C5 component) at an average price of $103.24 per barrel. At June 30, 2011, we had collars covering 189.1 Bcf of natural gas at weighted average floor and cap prices of $5.27 and $5.93 per mcf and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 and $80.00 per barrel. At June 30, 2011, we also had sold call options covering 2.7 million barrels of oil at a weighted average price of $83.15. The fair value of all of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of contract prices and a reference price, generally NYMEX, on June 30, 2011 was a net unrealized pre-tax gain of $61.1 million. The contracts expire monthly through December 2013. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or decreases in natural gas, NGLs and oil sales in the period the hedged production is sold. In the first six months of 2011, natural gas, NGLs and oil sales included realized hedging gains of $53.9 million compared to gains of $19.6 million in the same period of 2010.
     At June 30, 2011, the following commodity derivative contracts were outstanding:
                 
            Average
Period   Contract Type   Volume Hedged   Hedge Price
Natural Gas
               
2012
  Swaps   70,192 Mmbtu/day   $ 5.00  
2011
  Collars   333,200 Mmbtu/day   $ 5.38-$6.23  
2012
  Collars   189,641 Mmbtu/day   $ 5.32-$5.91  
2013
  Collars   160,000 Mmbtu/day   $ 5.09-$5.65  
 
               
Crude Oil
               
2012
  Collars   2,000 bbls/day   $ 70.00-$80.00  
2011
  Call options   5,500 bbls/day   $ 80.00  
2012
  Call options   4,700 bbls/day   $ 85.00  
 
               
NGLs
               
2011
  Swaps   7,000 bbls/day   $ 104.17  
2012
  Swaps   5,000 bbls/day   $ 102.59  
     Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas and oil production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value as unrealized derivative gains and losses in the accompanying consolidated balance sheets. We recognize all unrealized and realized gains and losses related to these contracts as derivative fair value income or loss in our consolidated statements of operations. As of June 30, 2011, derivatives on 53.7 Bcfe no longer qualify or are not designated for hedge accounting.

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Interest Rates
     At June 30, 2011, we had $1.8 billion of debt outstanding which bears interest at fixed rates averaging 6.9%.
Inflation and Changes in Prices
     Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas and oil prices and the costs to produce our reserves. Natural gas and oil prices are subject to fluctuations that are beyond our ability to control or predict. During second quarter 2011, we received an average of $3.76 per mcf of gas and $92.46 per barrel of oil before derivative contracts compared to $3.75 per mcf of gas and $67.76 per barrel of oil in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated through the middle of 2008, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure not only on our operating costs but also on capital costs. Due to the decline in commodity prices since then, costs have generally moderated but are increasing in areas with high levels of drilling activity that utilize specialized services for horizontal drilling and completions. We expect costs in 2011 to continue to be a function of supply and demand.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposures. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.
Market Risk
     Our major market risk is exposure to natural gas, NGL and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas, NGL and oil prices have been volatile and unpredictable for many years.
Commodity Price Risk
     We periodically enter into derivative arrangements with respect to our natural gas, oil and NGL production. These arrangements are intended to reduce the impact of natural gas and oil price fluctuations. Some of our derivatives have been swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establish a minimum floor price and a predetermined ceiling price. We have also entered into call option derivative contracts under which we sold call options in exchange for a premium from the counterparty. Historically, we applied hedge accounting to derivatives utilized to manage price risk associated with our natural gas and oil production. Accordingly, we recorded the change in the fair value of our swap and collar contracts under the balance sheet caption accumulated other comprehensive income and into natural gas, NGLs and oil sales when the forecasted sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge is reported currently each period in derivative fair value income or loss in our consolidated statements of operations. Some of our derivatives do not qualify for hedge accounting but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGL and oil production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value in unrealized derivative gains and losses in our consolidated balance sheets. We recognize all unrealized and realized gains and losses related to these contracts in derivative fair value income or loss in our consolidated statements of operations. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Our derivative counterparties include ten financial institutions, of which all but one are in our bank group. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.
     As of June 30, 2011, we had swaps covering 25.6 Bcf of natural gas and 3.1 million barrels of NGLs, collars covering 189.1 Bcf of natural gas and 0.7 million barrels of oil and oil call options for 2.7 million barrels of oil. These contracts expire monthly through December 2013. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of June 30, 2011, approximated a net unrealized pre-tax gain of $61.1 million.
     We expect our NGL production to continue to increase. In the first six months 2011, we entered into NGL swap contracts for the natural gasoline component (C5) of NGLs. In our Marcellus Shale operations, propane is a large product component of our NGL production and we believe NGL prices are somewhat seasonal. Therefore, the percentage of NGL prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand.

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     At June 30, 2011, the following commodity derivative contracts were outstanding:
                         
                    Fair Market Value
                    as of
                    June 30, 2011
Period   Contract Type   Volume Hedged   Average Hedge Price   Asset (Liability)
                    (in thousands)
Natural Gas
                       
2012
  Swaps   70,192 Mmbtu/day   $ 5.00     $ 4,184  
2011
  Collars   333,200 Mmbtu/day   $ 5.38-$6.23     $ 59,271  
2012
  Collars   189,641 Mmbtu/day   $ 5.32-$5.91     $ 42,298  
2013
  Collars   160,000 Mmbtu/day   $ 5.09-$5.65     $ 8,768  
 
                       
Crude Oil
                       
2012
  Collars   2,000 bbls/day   $ 70.00-$80.00     $ (15,830 )
2011
  Call options   5,500 bbls/day   $ 80.00     $ (17,768 )
2012
  Call options   4,700 bbls/day   $ 85.00     $ (33,582 )
 
                       
NGLs
                       
2011
  Swaps   7,000 bbls/day   $ 104.17     $ 5,797  
2012
  Swaps   5,000 bbls/day   $ 102.59     $ 7,952  
Other Commodity Risk
     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. We currently have not entered into any basis derivatives.
     The following table shows the fair value of our swaps, collars and call options and the hypothetical change in the fair value that would result from a 10% and a 25% change in commodity prices at June 30, 2011 (in thousands):
                                         
            Hypothetical Change in   Hypothetical Change in
            Fair Value   Fair Value
            Increase of   Decrease of
    Fair Value   10%   25%   10%   25%
Swaps
  $ 17,934     $ (42,676 )   $ (106,455 )   $ 42,932     $ 107,329  
Collars
    94,507       (92,270 )     (232,561 )     103,542       257,053  
Call options
    (51,351 )     (22,950 )     (60,069 )     20,198       40,886  
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
     As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported

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within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2011 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
     There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15-d-15(f) under the Exchange Act) during the quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION
ITEM 1A. RISK FACTORS
     We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

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ITEM 6. EXHIBITS
     (a) EXHIBITS
     
Exhibit    
Number   Exhibit Description
 
   
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)
 
   
3.2
  Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)
 
   
10.1
  Second Amendment to the Range Resources Corporation Amended and Restated 2005 Equity Based Compensation Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2011)
 
   
31.1*
  Certification by the Chairman 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 Chairman 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
 
   
101. INS**
  XBRL Instance Document
 
   
101. SCH**
  XBRL Taxonomy Extension Schema
 
   
101. CAL**
  XBRL Taxonomy Extension Calculation Linkbase Document
 
   
101. DEF**
  XBRL Taxonomy Extension Definition Linkbase Document
 
   
101. LAB**
  XBRL Taxonomy Extension Label Linkbase Document
 
   
101. PRE**
  XBRL Taxonomy Extension Presentation Linkbase Document
 
*   filed herewith
 
**   furnished herewith

41


 

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.
Date: July 25, 2011
         
  RANGE RESOURCES CORPORATION
 
 
  By:   /s/ ROGER S. MANNY    
    Roger S. Manny   
    Executive Vice President and Chief Financial Officer   
 
Date: July 25, 2011
         
  RANGE RESOURCES CORPORATION
 
 
  By:   /s/ DORI A. GINN    
    Dori A. Ginn   
    Principal Accounting Officer and Vice President Controller   
 

II-1


 

Exhibit index
     
Exhibit    
Number   Exhibit Description
 
   
3.1
  Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)
 
   
3.2
  Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)
 
   
10.1
  Second Amendment to the Range Resources Corporation Amended and Restated 2005 Equity Based Compensation Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2011)
 
   
31.1*
  Certification by the Chairman 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 Chairman 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
 
   
101. INS**
  XBRL Instance Document
 
   
101. SCH**
  XBRL Taxonomy Extension Schema
 
   
101. CAL**
  XBRL Taxonomy Extension Calculation Linkbase Document
 
   
101. DEF**
  XBRL Taxonomy Extension Definition Linkbase Document
 
   
101. LAB**
  XBRL Taxonomy Extension Label Linkbase Document
 
   
101. PRE**
  XBRL Taxonomy Extension Presentation Linkbase Document
 
*   filed herewith
 
**   furnished herewith

II-2