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CNX Gas 10-Q 2006
CNX GAS 10-Q
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the quarterly period ended June 30, 2006
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     
Commission file number: 001-32723
 
CNX GAS CORPORATION
(Exact name of registrant as specified in its charter)
 
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  20-3170639
(I.R.S. Employer
Identification No.)
4000 Brownsville Road
South Park, PA 15129
(412) 854-6719
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o            Accelerated filer o            Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act). Yes o No þ
The number of shares of the registrant’s common stock outstanding as of July 31, 2006 is 150,833,334 shares.
 
 

 


 

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 EX-10.1
 EX-10.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

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PART I
FINANCIAL INFORMATION
ITEM 1. CONDENSED FINANCIAL STATEMENTS
CNX GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

(Dollars in thousands, except per share data)
                                 
    For the three months ended     For the six months ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Revenue and Other Income:
                               
Outside Sales
  $ 92,194     $ 53,311     $ 193,987     $ 121,197  
Related Party Sales
    1,404       1,701       3,034       3,399  
Royalty Interest Gas Sales
    12,686       9,066       28,493       18,742  
Purchased Gas Sales
    9,778       44,975       32,130       69,257  
Other Income
    6,790       2,019       13,431       4,527  
 
                       
Total Revenue and Other Income
    122,852       111,072       271,075       217,122  
Costs and Expenses:
                               
Lifting Costs
    7,016       6,438       14,695       12,180  
Gathering and Compression Costs
    15,130       10,451       26,991       19,222  
Royalty Interest Gas Costs
    10,267       7,026       23,683       14,463  
Purchased Gas Costs
    9,986       45,592       32,751       70,086  
Other
    2,035       2,336       3,864       5,594  
Equity in (Earnings) Loss of Affiliates
    (625 )     (219 )     (772 )     132  
General and Administrative
    7,734       3,706       14,706       7,472  
Depreciation, Depletion and Amortization
    8,987       8,112       17,891       17,212  
Interest Expense
    2             9        
 
                       
Total Costs and Expenses
    60,532       83,442       133,818       146,361  
 
                       
Earnings Before Income Taxes
    62,320       27,630       137,257       70,761  
Income Taxes
    24,167       10,638       53,228       27,243  
 
                       
Net Income
  $ 38,153     $ 16,992     $ 84,029     $ 43,518  
 
                       
 
                               
Earnings per share:
                               
Basic
  $ 0.25     $ 0.14     $ 0.56     $ 0.35  
 
                       
Diluted
  $ 0.25     $ 0.14     $ 0.56     $ 0.35  
 
                       
 
                               
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,833,334       122,896,667       150,833,334       122,896,667  
 
                       
Dilutive
    151,060,061       122,988,359       151,004,996       122,988,359  
 
                       
The accompanying notes are an integral part of these consolidated financial statements.

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CNX GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
                 
    (Unaudited)        
    June 30,     December 31,  
    2006     2005  
ASSETS
               
Current Assets:
               
Cash and Cash Equivalents
  $ 64,307     $ 20,073  
Accounts Receivable:
               
Trade
    28,493       41,121  
Related Party
    3,518       728  
Other
    693       550  
Derivatives
    3,923        
Deferred Taxes
          9,339  
Other Current Assets
    22,202       18,067  
 
           
Total Current Assets
    123,136       89,878  
Property, Plant and Equipment, Net
    786,679       723,547  
Other Assets
    11,964       11,903  
Investments in Equity Affiliates
    50,196       49,528  
 
           
TOTAL ASSETS
  $ 971,975     $ 874,856  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities:
               
Accounts Payable
  $ 11,365     $ 22,541  
Accrued Royalties Payable
    11,051       10,504  
Accrued Severance Taxes
    2,266       2,747  
Accrued Income Taxes
    5,069       5,518  
Derivatives
          23,777  
Deferred Taxes
    1,530        
Other Current Liabilities
    25,489       21,071  
 
           
Total Current Liabilities
    56,770       86,158  
Deferred Taxes
    78,673       47,736  
Other Liabilities
    15,681       14,310  
Well Plugging Liabilities
    8,328       10,908  
Derivatives
    18,896       32,909  
Postemployment Benefits Other Than Pension
    3,357       3,363  
 
           
Total Liabilities
    181,705       195,384  
 
           
Stockholders’ Equity
               
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,833,334 Issued and Outstanding at June 30, 2006 and December 31, 2005
    1,508       1,508  
Capital in Excess of Par Value
    779,430       779,509  
Retained Earnings (Deficit)
    18,499       (65,530 )
Accumulated Other Comprehensive Loss
    (9,167 )     (34,733 )
Stock Based Compensation Awards
          (1,282 )
 
           
Total Stockholders’ Equity
    790,270       679,472  
 
           
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 971,975     $ 874,856  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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CNX GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)

(Dollars in thousands)
                                                 
                            Accumulated              
            Capital in     Retained     Other     Stock Based     Total  
    Common     Excess of     Earnings/     Comprehensive     Compensation     Stockholders’  
    Stock     Par Value     (Deficit)     Income (Loss)     Awards     Equity  
Balance at December 31, 2005
  $ 1,508     $ 779,509     $ (65,530 )   $ (34,733 )   $ (1,282 )   $ 679,472  
 
Net Income
                84,029                   84,029  
 
Gas Cash Flow Hedge (Net of $(16,427) tax)
                      25,566             25,566  
 
                                   
 
Comprehensive Income (a)
                84,029       25,566             109,595  
Elimination of Unearned Compensation on Restricted Stock Units
          (1,282 )                 1,282        
Amortization of Stock Based Compensation Awards
          1,203                         1,203  
 
                                   
Balance at June 30, 2006
  $ 1,508     $ 779,430     $ 18,499     $ (9,167 )   $     $ 790,270  
 
                                   
 
(a)   Of the $25,566 net change in accumulated other comprehensive income in the period, $3,944 represents hedging gains recognized in net income for the portions of the financial hedges that settled in the current period. Comprehensive loss for the period ended June 30, 2005 was $9,348.
The accompanying notes are an integral part of these consolidated financial statements.

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CNX GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(Dollars in thousands)
                 
    For The Six Months Ended  
    June 30,  
    2006     2005  
Operating Activities:
               
Net Income
  $ 84,029     $ 43,518  
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
               
Depreciation, Depletion and Amortization
    17,891       17,212  
Stock Based Compensation
    1,203        
Income Taxes
    (449 )     14,203  
Deferred Income Taxes
    25,379       13,040  
Equity in (Earnings) Loss of Affiliates
    (772 )     132  
Changes in Operating Assets:
               
Accounts Receivable
    12,485       (605 )
Related Party Receivable
    (2,790 )      
Other Current Assets
    56       (4,068 )
Changes in Other Assets
    (61 )     374  
Changes in Operating Liabilities:
               
Accounts Payable
    (11,176 )     (8,309 )
Other Current Liabilities
    (758 )     4,978  
Changes in Other Liabilities
    1,511       1,160  
Other
    285       128  
 
           
Net Cash Provided by Operating Activities
    126,833       81,763  
 
           
 
Investing Activities:
               
Capital Expenditures
    (83,009 )     (36,642 )
Investment in Equity Affiliates
    104       (2,762 )
 
           
Net Cash Used in Investing Activities
    (82,905 )     (39,404 )
 
           
 
Financing Activities:
               
Short-Term Loan
    306        
Payments to Parent
          (42,362 )
 
           
Net Cash Provided by (Used in) Financing Activities
    306       (42,362 )
Net Increase in Cash and Cash Equivalents
    44,234       (3 )
Cash and Cash Equivalents at Beginning of Period
    20,073       3  
 
           
Cash and Cash Equivalents at End of Period
  $ 64,307     $  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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CNX GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands)
Note 1—Basis of Presentation:
     The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six month periods ended June 30, 2006 are not necessarily indicative of the results that may be expected for future periods.
     The balance sheet at December 31, 2005 has been derived from the audited consolidated financial statements at that date but does not include all of the notes required by accounting principles generally accepted in the United States of America for complete financial statements.
     For further information, refer to the consolidated financial statements and related notes included in CNX Gas Corporation’s (CNX Gas) Form 10-K for the year ended December 31, 2005.
     Certain reclassifications of previously reported data have been made to conform to the three and six months ended June 30, 2006 classifications.
     Effective January 1, 2006, CNX Gas adopted Emerging Issues Task Force on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of Accounting Principles Board Opinion No. 29, “Accounting for Nonmonetary Transactions”. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. In accordance with EITF 04-13, CNX Gas has applied this accounting to new or modified agreements after January 1, 2006 which resulted in the combining of $35,276 of revenue and $36,749 of expense in the three months ended June 30, 2006 and $60,505 of revenue and $62,686 of expense in the six months ended June 30, 2006. Previously, these transactions were recorded on a gross basis. The adoption of EITF 04-13 did not have an impact on net income or cash flows.
     Effective January 1, 2006, CNX Gas adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (SFAS 123R), using the modified prospective transition method and therefore has not restated results for prior periods. Under this transition method, stock-based compensation expense for the three and six months ended June 30, 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of January 2006, based on the grant date fair value estimated in accordance with the original provision of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). Stock-based compensation expense for all stock-based compensation awards granted after January 1, 2006 is based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. CNX Gas recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. Prior to the adoption of SFAS 123R, CNX Gas recognized stock-based compensation expense in accordance with Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (APB 25). In March 2005, the Securities and Exchange Commission (the SEC) issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC’s interpretation of SFAS 123R and the valuation of share-based payments for public companies. CNX Gas has applied the provisions of SAB 107 in its adoption of SFAS 123R. See Note 2 to the Consolidated Condensed Financial Statements for a further discussion on stock-based compensation.
     Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the reporting period. Diluted earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the effect of dilutive potential common shares outstanding during the period as calculated in accordance with SFAS 123R. The number of additional shares is calculated by assuming that restricted stock units were converted and outstanding stock options were exercised and that the proceeds from such activity was used to acquire shares of common stock at the average market price during the reporting period.

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     The computations for basic and diluted earnings per share are as follows:
                                 
    For the three months ended     For the six months ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Net Income
  $ 38,153     $ 16,992     $ 84,029     $ 43,518  
 
                       
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,833,334       122,896,667       150,833,334       122,896,667  
Effect of stock options
    226,727       91,692       171,662       91,692  
 
                       
Diluted
    151,060,061       122,988,359       151,004,996       122,988,359  
 
                       
 
                               
Earnings per share:
                               
Basic
  $ 0.25     $ 0.14     $ 0.56     $ 0.35  
 
                       
Diluted
  $ 0.25     $ 0.14     $ 0.56     $ 0.35  
 
                       
Note 2—Stock-Based Compensation:
     CNX Gas adopted the CNX Gas Equity Incentive Plan on June 30, 2005, and amended the plan on August 1, 2005. The amended plan was approved by the sole stockholder of CNX Gas at that time, CONSOL Energy Inc (CONSOL Energy), on August 4, 2005. The plan is administered by our board of directors and the board of directors may delegate administration of the plan to a committee of the board of directors. Our directors, employees and consultants and our affiliates’ (which include CONSOL Energy) directors, employees and consultants are eligible to receive awards under the plan. Some of our employees, including our executive officers and non-employee directors, have participated in, or have been eligible to participate in and will continue to be eligible to participate in the CNX Gas Equity Incentive Plan.
     The CNX Gas Equity Incentive Plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under the CNX Gas Equity Incentive Plan is 2,500,000.
     The total stock-based compensation expense was $732 and $1,203 for the three and six months ended June 30, 2006 and the related deferred tax benefit totaled $283 and $466, respectively. Prior to January 1, 2006, CNX Gas accounted for stock-based compensation under the recognition and measurement provisions of APB 25. Under APB 25, no stock-based employee compensation cost for stock options was reflected in net income, as all options granted under the plans had an exercise price equal to the market value of the underlying common stock on the date of the grant.
     Prior to January 1, 2006, CNX Gas provided pro forma disclosure amounts in accordance with Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure – an Amendment of SFAS No. 123” (SFAS 148), as if the fair value method defined by SFAS 123 had been applied to its stock-based compensation.
     Effective January 1, 2006, CNX Gas adopted the fair value recognition provisions of SFAS 123R using the modified prospective transition method, and therefore has not restated results for prior periods. Under this transition method, stock-based compensation expense for the three and six months ended June 30, 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested, as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. CNX Gas recognizes compensation costs for shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term.
As a result of adopting SFAS 123R, pretax income and net income for the three months ended June 30, 2006 was $598 and $367 lower, respectively, than if we had continued to account for stock-based compensation under APB 25. Pretax income and net income for the six months ended June 30, 2006 was $945 and $580 lower, respectively, than if we had continued to account for stock-based compensation under APB 25. The impact on basic earnings per share for the three months ended June 30, 2006 was $0.01 per share. Basic earnings per share for the six months ended June 30, 2006 and diluted earnings per share for the three and six months ended June 30, 2006 were not impacted. Upon the adoption of SFAS 123R, tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options will be classified as financing cash flows when CNX Gas options are exercised in the future. As of June 30, 2006, there were no options exercised.

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     As part of its SFAS 123R adoption, CNX Gas used the Black-Scholes option pricing model to value the options. The risk free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S Treasury obligations for the expected term of the award. The expected volatility and expected life of the awards were developed by examining the stock option activity for a peer group of companies. The fair value of share based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:
         
    For the six months
    ended June 30, 2006
Weighted Average Fair Value of Grants
  $ 9.83  
Risk Free Interest Rate
    4.63 %
Dividend Yield
     
Expected Volatility
    32.2 %
Expected life in years
    4.5  
     There were no awards granted during the three and six months ended June 30, 2005. Therefore, there are no applicable assumptions for this period.
     Option activity under the CNX Gas Equity Incentive Plan during the six months ended June 30, 2006 was as follows:
                                 
                    Weighted        
                    Average        
            Weighted     Remaining     Aggregate  
            Average     Contractual     Intrinsic  
            Exercise     Term     Value  
    Shares     Price     (in years)     (in thousands)  
Outstanding at December 31, 2005
    1,040,576     $ 16.05                  
Granted
    460,994       28.50                  
Exercised
                           
Forfeited
    (28,835 )     18.87                  
 
                             
Outstanding at June 30, 2006
    1,472,735     $ 19.89       9.32     $ 14,882  
 
                       
Vested and expected to vest at June 30, 2006
    1,472,735     $ 19.89       9.32     $ 14,882  
 
                       
     At June 30, 2006, there were no exercisable options. There were no options outstanding at any time during the six month period ended June 30, 2005.
     These stock options will terminate ten years after the date on which they were granted. The employee stock options granted prior to April 28, 2006 vest 25% per year, beginning one year after the grant date; options granted on or after April 28, 2006 vest 100% on the third anniversary of the date of grant. As of June 30, 2006, there are 1,454,930 shares of common stock underlying stock options outstanding under this plan for employees. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 17,805 non-employee director stock options outstanding at June 30, 2006. The vesting of the options will accelerate in the event of death, disability or retirement and may accelerate upon a change of control of CNX Gas.
     The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX Gas’ closing stock price on the last trading day of the six months ended June 30, 2006 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on June 30, 2006. This amount changes based on the fair market value of CNX Gas’ stock.
     As of June 30, 2006, $9,769 of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of 2.87 years.
     Under the CNX Gas Equity Incentive Plan, CNX Gas granted certain employees and certain directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. A total of 99,112 restricted stock units were outstanding at June 30, 2006, vesting over a weighted average remaining period of 2.16 years. Compensation expense will be recognized over the vesting period of the units. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of the grant:

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            Weighted Average
    Number of Shares     Grant Date Fair Value
Nonvested at December 31, 2005
    92,969     $ 16.00  
Granted
    6,143       28.50  
 
             
Nonvested at June 30, 2006
    99,112     $ 16.77  
 
             
Note 3—Pension and Other Postemployment Benefits:
     The components of net periodic benefit costs are as follows:
                                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    Pension     Other Benefits     Pension     Other Benefits  
    2006     2006     2005     2006     2006     2005  
Components of Net Periodic Benefit Costs:
                                               
Service costs
  $ 70     $ 23     $ 32     $ 140     $ 46     $ 64  
Interest costs
    1       25       41       2       50       82  
Amortization of prior service costs credit
    (2 )     (43 )     (29 )     (4 )     (86 )     (58 )
Recognized net actuarial loss (gain)
    (3 )           16       (6 )           32  
 
                                   
Benefit costs
  $ 66     $ 5     $ 60     $ 132     $ 10     $ 120  
 
                                   
     As previously disclosed in the notes to its audited consolidated financial statements for the year ended December 31, 2005, CNX Gas does not expect to contribute to the other postemployment benefit plan in 2006. We intend to pay benefit claims as they become due. For the three and six months ended June 30, 2006, there were $16 in payments made pursuant to the other postemployment benefit plan.
     As previously disclosed in the notes to our audited consolidated financial statements for the year ended December 31, 2005, CNX Gas employees were part of the CONSOL Energy pension plan until December 31, 2005. Effective January 1, 2006, an identical plan was created, sponsored by CNX Gas, to provide a benefit for all service accruals going forward. In the three and six months ended June 30, 2006, CNX Gas made an initial contribution of $20 to the pension plan.
Note 4—Income Taxes:
     The following is a reconciliation, stated in dollars and as a percentage of pretax income, of the U.S. statutory federal income tax rate to CNX Gas’ effective tax rate:
                                 
    For the Six Months Ended June 30,  
    2006     2005  
    Dollars     Rate     Dollars     Rate  
Statutory U.S. Federal Income Tax Rate
  $ 48,040       35.0 %   $ 24,766       35.0 %
Net Effect of State Income Tax
    6,080       4.4 %     2,972       4.2 %
Other
    (892 )     (0.6 )%     (495 )     (0.7 )%
 
                       
Income Tax Expense/ Effective Rate
  $ 53,228       38.8 %   $ 27,243       38.5 %
 
                       
     CNX Gas files its federal tax return and some of its state tax returns as a member of the CONSOL Energy consolidated group. Income taxes are calculated as if CNX Gas had filed a tax return on a separate company basis. Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CNX Gas’ financial statements or separate tax return that would be filed on a stand alone company basis. The effective tax rate for the six months ended June 30, 2006 and 2005 was calculated using the annual effective rate projection on recurring earnings.

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Note 5—Property, Plant and Equipment:
                 
    June 30,     December 31,  
    2006     2005  
Surface Lands
  $ 31,927     $ 26,573  
Mineral Interests
    55,621       55,621  
Wells and Related Equipment
    158,206       141,959  
Intangible Drilling
    342,692       312,467  
Gathering Assets
    373,026       344,355  
Gas Well Plugging
    4,954       7,680  
Other
    3,274       36  
 
           
Total Property, Plant and Equipment
    969,700       888,691  
Accumulated Depreciation, Depletion and Amortization
    (183,021 )     (165,144 )
 
           
Property and Equipment, net
  $ 786,679     $ 723,547  
 
           
Note 6—Credit Facility:
     CNX Gas entered into a credit agreement for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. We may use borrowings under the credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. The $200,000 credit agreement for CNX Gas is unsecured, however it does contain a negative pledge provision providing that CNX Gas assets cannot be used to secure any other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CNX Gas stock and merge with another corporation. The facility includes a leverage ratio covenant of not more than 3.0 to 1.0, measured quarterly. As there was no debt (for purposes of calculating the leverage ratio) outstanding at June 30, 2006, the leverage ratio was 0.0 to 1.0 at June 30, 2006. The facility also includes an interest coverage ratio of no less than 3.0 to 1.0 measured quarterly. The interest coverage ratio was also met at June 30, 2006.
     At June 30, 2006, the CNX Gas credit agreement had no borrowings outstanding and $16,847 of letters of credit outstanding, leaving $183,153 of capacity available for borrowings and the issuance of letters of credit.
     As a result of entering into the $200,000 credit agreement, CNX Gas and subsidiaries executed a Supplemental Indenture and are guarantors of CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture and the agreement governing CONSOL Energy’s 8.25% medium term notes due 2007 in the principal amount of $45,000 would require CNX Gas to ratably secure both the 7.875% notes and 8.25% medium term notes.
Note 7—Commitments and Contingent Liabilities:
     CNX Gas has various purchase commitments for materials, supplies and items of permanent investment incidental to the ordinary conduct of business. Such commitments are not at prices in excess of current market value.
     In 2004, Yukon Pocahontas Coal Company, Buchanan Coal Company, and Sayers-Pocahontas Coal Company filed a complaint against Consolidation Coal Company (“CCC”), a subsidiary of CONSOL Energy Inc., in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC’s Buchanan Mine into nearby void spaces at the mine of one of CONSOL Energy’s other subsidiaries, Island Creek Coal Company (“ICCC”). CCC believes that it had, and continues to have, the right to store water in these void areas. On July 26, 2006, the plaintiffs filed a motion to amend the original complaint seeking, among other things, to add CONSOL Energy, ICCC and CNX Gas Company LLC as additional defendants. As to the additional defendants, the proposed amended complaint alleges, among other things, that CNX Gas Company LLC, as lessee and operator under certain coalbed methane gas leases from plaintiffs, had a duty to prevent CCC from depositing water into the mine voids and failed to do so. The proposed amended complaint seeks $150,000 in damages from the additional defendants, plus costs, interest and attorneys’ fees. CNX Gas Company LLC denies that it has any liability in this matter and intends to vigorously defend this action if it is ultimately added as a defendant.
     In October 2005, CDX Gas, LLC (CDX) alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX demanded that we enter into a business arrangement with CDX to use its patented technology. Alternatively, CDX informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly

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covered by their patents. We believe that approximately 27 of our producing wells to date could be covered by their claim. We deny all of these allegations and intend to vigorously contest them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania (C.A. No. 05-1574), seeking a judicial determination that we do not infringe any valid CDX patents. CDX filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain of their patents. Fact discovery has been completed. A hearing with regard to the scope of the asserted CDX patents occurred before a Court-appointed Special Master on July 14, 2006. We cannot predict the outcome of this lawsuit; however, CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
     CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2001. For these years, CNX Gas has filed appropriate returns and has paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County as of June 30, 2006. Additionally, on April 29, 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a “Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code §8.01-184” against us in circuit court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002. The complaint alleges that we failed to properly calculate the amount of license tax we owed to Buchanan County related to our production and sale of CBM gas in Buchanan County. Buchanan County is seeking a determination by the court that we have calculated, and continue to calculate, the license tax in an improper manner. In April 2006, Buchanan County filed a similar complaint with respect to years 2003 and 2004. We have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability on our balance sheet in an amount based on the difference between our calculation of the tax and Buchanan County’s calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
     In 1999, CNX Gas was named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty owners and to a class of plaintiffs who have yet to be determined. The claim of underpayment of royalties related to the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post production expenses of gathering compression and transportation. CNX Gas was ordered to, and subsequently paid in 2002, approximately $7,000 to the group of royalty owners that brought the suit. A final payment was made to the plaintiffs in 2003 for approximately $6,000 to adjust all royalties owed to the plaintiffs from the date of the court ruling forward, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of the aforementioned suit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various royalty owners using the court determined deductions from the settled case. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
     In addition to the foregoing, CNX Gas is subject to various pending and threatened lawsuits and claims arising in the ordinary course of its business. While the relief claimed in these matters may be significant, we are unable to predict with certainty the ultimate outcome of such lawsuits and claims. We have established reserves for pending litigation which we believe are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against CNX Gas will not materially affect the financial position of CNX Gas.

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     At June 30, 2006, CNX Gas has provided the following financial guarantees. CNX Gas management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition. The fair value of all liabilities associated with these guarantees have been properly recorded and reported in the financial statements.
                                         
    Total                              
    Amounts     Less Than                     Beyond  
    Committed     1 Year     1-3 Years     3-5 Years     5 years  
Letters of Credit:
                                       
Gas
  $ 16,847     $ 16,847     $     $     $  
 
                             
Total Letters of Credit
  $ 16,847     $ 16,847     $     $     $  
Surety Bonds:
                                       
Environmental
  $ 495     $ 495     $     $     $  
Other
    474       439       35              
 
                             
Total Surety Bonds
  $ 969     $ 934     $ 35     $     $  
Other:
                                       
Guarantees
  $ 6,100     $ 5,000     $ 1,100     $     $  
 
                             
Total Guarantees
  $ 6,100     $ 5,000     $ 1,100     $     $  
 
                             
Total Commitments
  $ 23,916     $ 22,781     $ 1,135     $     $  
 
                             
     As previously disclosed in the notes to our audited consolidated financial statements for the year ended December 31, 2005, CONSOL Energy has also provided certain parental guarantees related to activity associated with CNX Gas. CNX Gas anticipates that these parental guarantees will be transferred from CONSOL Energy to CNX Gas over time. CNX Gas management believes these parental guarantees will also expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.
Note 8—Segment Information:
     The principal activity of CNX Gas is to produce pipeline quality methane gas for sale primarily to gas wholesalers. CNX Gas has three reportable operating segments: Central Appalachia and Tennessee, Northern Appalachia, and Gathering. These operating segments reflect the way CNX Gas manages operations and makes business decisions.
     Industry segment results for the three months ended June 30, 2006 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 87,345     $ 4,849     $     $ 92,194     $     $ 92,194  
Sales—related parties
    1,387       17             1,404             1,404  
Sales—royalty interest
    12,628       58             12,686             12,686  
Sales—purchased gas
    9,778                   9,778             9,778  
Other revenue
    6,431       16       343       6,790             6,790  
Intersegment revenues
                13,215       13,215       (13,215 )      
 
                                   
Total Revenue and Other Income
  $ 117,569     $ 4,940     $ 13,558     $ 136,067     $ (13,215 )   $ 122,852  
 
                                   
Earnings Before Income Taxes
  $ 57,610     $ 712     $ 3,998     $ 62,320     $     $ 62,320 (A)
 
                                   
Segment assets
  $ 553,042     $ 44,487     $ 310,139     $ 907,668     $ 64,307     $ 971,975 (B)(C)
 
                                   
Depreciation, depletion and amortization
  $ 5,251     $ 647     $ 3,089     $ 8,987     $     $ 8,987  
 
                                   
Capital expenditures
  $ 22,348     $ 5,853     $ 14,631     $ 42,832     $     $ 42,832  
 
                                   
 
(A)   Central Appalachia and Tennessee segment includes equity in earnings of unconsolidated affiliates of $625.
 
(B)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $50,196.
 
(C)   The $64,307 represents cash which is not allocated to individual segments.

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     Industry segment results for the three months ended June 30, 2005 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 49,801     $ 3,510     $     $ 53,311     $     $ 53,311  
Sales—related parties
    1,687       14             1,701             1,701  
Sales—royalty interest
    9,020       46             9,066             9,066  
Sales—purchased gas
    44,975                   44,975             44,975  
Other revenue
    1,506       13       500       2,019             2,019  
Intersegment revenues
                11,128       11,128       (11,128 )      
 
                                   
Total Revenue and Other Income
  $ 106,989     $ 3,583     $ 11,628     $ 122,200     $ (11,128 )   $ 111,072  
 
                                   
Earnings (Loss) Before Income Taxes
  $ 25,395     $ (290 )   $ 2,525     $ 27,630     $     $ 27,630 (D)
 
                                   
Segment assets
  $ 413,612     $ 25,510     $ 307,667     $ 746,789     $     $ 746,789 (E)
 
                                   
Depreciation, depletion and amortization
  $ 4,393     $ 842     $ 2,877     $ 8,112     $     $ 8,112  
 
                                   
Capital expenditures
  $ 22,554     $ 3,275     $ 46     $ 25,875     $     $ 25,875  
 
                                   
 
(D)   Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of $(219).
 
(E)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $50,003.
     Industry segment results for the six months ended June 30, 2006 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 182,502     $ 11,485     $     $ 193,987     $     $ 193,987  
Sales—related parties
    2,981       53             3,034             3,034  
Sales—royalty interest
    28,372       121             28,493             28,493  
Sales—purchased gas
    32,130                   32,130             32,130  
Other revenue
    12,738       27       666       13,431             13,431  
Intersegment revenues
                26,223       26,223       (26,223 )      
 
                                   
Total Revenue and Other Income
  $ 258,723     $ 11,686     $ 26,889     $ 297,298     $ (26,223 )   $ 271,075  
 
                                   
Earnings (Loss) Before Income Taxes
  $ 125,669     $ 3,385     $ 8,203     $ 137,257     $     $ 137,257 (F)
 
                                   
Segment assets
  $ 553,042     $ 44,487     $ 310,139     $ 907,668     $ 64,307     $ 971,975 (G)(H)
 
                                   
Depreciation, depletion and amortization
  $ 10,491     $ 1,221     $ 6,179     $ 17,891     $     $ 17,891  
 
                                   
Capital expenditures
  $ 44,636     $ 12,504     $ 25,869     $ 83,009     $     $ 83,009  
 
                                   
 
(F)   Central Appalachia and Tennessee segment includes equity in earnings of unconsolidated affiliates of $772.
 
(G)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $50,196.
 
(H)   The $64,307 represents cash which is not allocated to individual segments.

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     Industry segment results for the six months ended June 30, 2005 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 114,606     $ 6,591     $     $ 121,197     $     $ 121,197  
Sales—related parties
    3,372       27             3,399             3,399  
Sales—royalty interest
    18,686       56             18,742             18,742  
Sales—purchased gas
    69,257                   69,257             69,257  
Other revenue
    3,997       30       500       4,527             4,527  
Intersegment revenues
                23,172       23,172       (23,172 )      
 
                                   
Total Revenue and Other Income
  $ 209,918     $ 6,704     $ 23,672     $ 240,294     $ (23,172 )   $ 217,122  
 
                                   
Earnings (Loss) Before Income Taxes
  $ 66,247     $ (56 )   $ 4,570     $ 70,761     $     $ 70,761 (I)
 
                                   
Segment assets
  $ 413,612     $ 25,510     $ 307,667     $ 746,789     $     $ 746,789 (J)
 
                                   
Depreciation, depletion and amortization
  $ 10,229     $ 1,228     $ 5,755     $ 17,212     $     $ 17,212  
 
                                   
Capital expenditures
  $ 30,999     $ 5,542     $ 101     $ 36,642     $     $ 36,642  
 
                                   
 
(I)   Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of $(132).
 
(J)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $50,003.
Note 9—Recent Accounting Pronouncements:
     In July 2006, the Financial Accounting Standards Board (FASB) released FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109” (FIN 48). FIN 48 provides a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. We are in the process of evaluating the financial impact of adopting FIN 48, which will be effective for us beginning in 2007.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report. This Current Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. See “Forward Looking Statements.”
     Unless the context otherwise requires, “we,” “us,” “our” and CNX Gas mean CNX Gas Corporation and its consolidated subsidiaries. Unless noted otherwise, production figures are exclusive of production attributable to equity affiliates.
Overview
     We are a natural gas exploration, development, production and gathering company with operations in the Appalachian Basin. We have operations in several states in the Appalachian Basin. We primarily are a coalbed methane (CBM) gas producer with industry-leading expertise in this type of gas extraction.
     Effective as of August 8, 2005, we separated our gas business from CONSOL Energy. The success of our operations substantially depends upon rights we received from CONSOL Energy. As a part of our separation from CONSOL Energy, CONSOL Energy transferred to us various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM and natural gas and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with their coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will, among other things, provide us certain corporate staff services and coordinate our tax filings.
     In August 2005, CNX Gas sold 27.9 million shares of common stock in a private placement transaction. The aggregate net proceeds of the transaction (approximately $420.2 million) were used to pay a special dividend to CONSOL Energy. CONSOL Energy continues to beneficially own approximately 81.5% of our outstanding common stock.
     Our financial statements are consolidated into CONSOL Energy’s financial statements.
Operations
     We produced 13.7 Bcf in the quarter ended June 30, 2006, and 27.3 Bcf for the six months ended June 30, 2006.
     During the quarter ended June 30, 2006, CNX Gas began production from 60 new CBM wells in Central Appalachia giving us a total of 128 new wells for the six months ended June 30, 2006. No additional wells were placed into production in Northern Appalachia since the 1 new well that was put into production in the first quarter. The Northern Appalachia 2006 drilling program began in May with the arrival of newly refurbished rigs. In Tennessee, no additional wells were placed into production since the 1.25 net wells began production in the first quarter. The foregoing well information is exclusive of any gob well activity.
     In addition to new wells, production in the June 2006 quarter was also higher than the June 2005 quarter as the June 2005 quarter was negatively affected by an issue at CONSOL Energy’s Buchanan Mine.
Outlook
     Second quarter production exceeded our expectations as anticipated interstate pipeline maintenance curtailments did not occur. However, interstate pipeline maintenance curtailments are expected to affect the third quarter. The impact of such curtailments will largely be determined by the in-service date of the Jewell Ridge lateral pipeline, which will permit us largely to avoid those curtailments. Thus, despite higher than expected production in the first six months of 2006, we maintain our forecast of total net production of 55.7 Bcf in 2006 (including equity affiliates).
     In Northern Appalachia, we expect to drill 20 wells in 2006, down from the 23 originally planned. At our Knox Energy joint venture in Tennessee, we have a farm-out agreement that permits us to elect to participate in wells on a well-by-well basis, but we do not control the drilling. We originally planned to participate in 47 net wells in Tennessee in 2006, with a drilling budget of $14 million. We are transferring most of this capital to our Central Appalachia operations, where we expect to drill approximately 250 wells in 2006, up from our original plan of 215 wells.

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Results of Operations
Three Months Ended June 30, 2006 compared with Three Months Ended June 30, 2005
(Amounts reported in thousands)
Net Income
     Net income changed primarily due to the following items:
                                 
                    Dollar       Percentage
    2006     2005     Variance       Change
Revenue and Other Income:
                               
Outside Sales
  $ 92,194     $ 53,311     $ 38,883       72.9  %
Related Party Sales
    1,404       1,701       (297 )     (17.5 )%
Royalty Interest Gas Sales
    12,686       9,066       3,620       39.9  %
Purchased Gas Sales
    9,778       44,975       (35,197 )     (78.3 )%
Other Income
    6,790       2,019       4,771       236.3  %
 
                       
Total Revenue and Other Income
    122,852       111,072       11,780       10.6  %
Costs and Expenses:
                               
Lifting Costs
    7,016       6,438       578       9.0  %
Gathering and Compression Costs
    15,130       10,451       4,679       44.8  %
Royalty Interest Gas Costs
    10,267       7,026       3,241       46.1  %
Purchased Gas Costs
    9,986       45,592       (35,606 )     (78.1 )%
Other
    2,035       2,336       (301 )     (12.9 )%
Equity in Earnings of Affiliates
    (625 )     (219 )     (406 )     (185.4 )%
General and Administrative
    7,734       3,706       4,028       108.7  %
Depreciation, Depletion and Amortization
    8,987       8,112       875       10.8  %
Interest Expense
    2             2       100.0  %
 
                       
Total Costs and Expenses
    60,532       83,442       (22,910 )     (27.5 )%
 
                       
Earnings Before Income Taxes
    62,320       27,630       34,690       125.6  %
Income Taxes
    24,167       10,638       13,529       127.2  %
 
                       
Net Income
  $ 38,153     $ 16,992     $ 21,161       124.5  %
 
                       
     Net income for 2006 was improved primarily due to additional production and increased average sales prices, while also managing costs. The increased revenues were offset, in part, by higher costs attributable to production taxes, firm transportation charges and general and administrative charges.
Revenue and Other Income
     Revenue and other income increased due to the following items:
                                 
                    Dollar       Percentage
    2006     2005     Variance       Change
Revenue and Other Income:
                               
Outside Sales
  $ 92,194     $ 53,311     $ 38,883       72.9  %
Related Party Sales
    1,404       1,701       (297 )     (17.5 )%
Royalty Interest Gas Sales
    12,686       9,066       3,620       39.9  %
Purchased Gas Sales
    9,778       44,975       (35,197 )     (78.3 )%
Other Income
    6,790       2,019       4,771       236.3  %
 
                         
Total Revenue and Other Income
  $ 122,852     $ 111,072     $ 11,780       10.6  %
 
                         

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     The increase in revenue was primarily due to additional production and a higher average sales price per thousand cubic feet in 2006 compared to 2005.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    13.7       11.2       2.5       22.3 %
Average Sales Price (per Mcf)
  $ 6.83     $ 4.91     $ 1.92       39.1 %
     Although average market prices period to period are relatively flat, the increase in average sales price is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, when a large portion of production was locked in at prices lower than the current period market prices. Periodically, CNX Gas enters into physical fixed price gas supply transactions with both gas marketers and end users for terms varying in length. CNX Gas also enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. For the three months ended June 30, 2006, these physical and financial hedges represented approximately 4.6 Bcf of our gas sales volumes at an average price of $7.73 per Mcf, compared to approximately 9.8 Bcf at an average price of $4.62 per Mcf for the three months ended June 30, 2005. Sales volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    1.9       1.6       0.3       18.8 %
Average Sales Price (per Mcf)
  $ 6.82     $ 5.66     $ 1.16       20.5 %
     Included in royalty interest gas sales are the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. Although average market prices period to period are relatively flat, the increase in average sales price is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, where a large portion of production was locked in at prices lower than the current period market prices. Sales volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Purchased Gas Sales Volumes (Bcf)
    1.4       6.4       (5.0 )     (78.1 )%
Average Sales Price (per Mcf)
  $ 6.80     $ 7.03     $ (0.23 )     (3.3 )%
     Included in purchased gas sales revenue are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia Gas Transmission Corporation (TCO) pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force on Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 on January 1, 2006, purchased gas sales and volumes have decreased. EITF 04-13 allows for the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. The net result for transactions that meet the above criteria is reflected in transportation expense in the current year. Additionally, there are low volumes of gas we purchase from third party producers at market prices less our gathering charge, which we then resell.
     Other income consists of insurance settlements, royalty income, third party gathering revenue, interest income and other miscellaneous income:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Insurance Settlements
  $ 3,960     $     $ 3,960       100.0 %
Royalty Income
    1,693       1,685       8       0.5 %
Interest Income
    728             728       100.0 %
Third Party Gathering Revenue
    343       283       60       21.2 %
Other Miscellaneous
    66       51       15       29.4 %
 
                         
Total Other Income
  $ 6,790     $ 2,019     $ 4,771       236.3 %
 
                         

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     The insurance settlements component of other income consists of business interruption insurance proceeds related to a CONSOL Energy mine incident in 2005 which negatively impacted our gas production in that year. Additional settlements may be forthcoming pending final resolution of the claim.
     Royalty income received from third parties is calculated as a percentage of the third parties’ sales price, which is comparable period to period.
     Interest income increased in 2006, as a result of CNX Gas retaining cash collections as a separate stand alone company. As of the June 30, 2005, CNX Gas was still part of CONSOL Energy and retained no cash resulting in zero interest income.
     Third party gathering revenue has increased due to additional volumes being transported through our gathering systems in 2006 compared to 2005.
     Other miscellaneous income increased due to various transactions, none of which are individually material.
Costs and Expenses
     Overall, costs and expenses decreased in 2006 primarily due to lower purchased gas costs. However, our operating costs and expenses increased in 2006 and are made up of the following components:
                                 
                    Dollar     Percentage
    2006     2005     Variance     Change
Costs and Expenses:
                               
Lifting Costs
  $ 7,016     $ 6,438     $ 578       9.0  %
Gathering and Compression Costs
    15,130       10,451       4,679       44.8  %
Royalty Interest Gas Costs
    10,267       7,026       3,241       46.1  %
Purchased Gas Costs
    9,986       45,592       (35,606 )     (78.1 )%
Other
    2,035       2,336       (301 )     (12.9 )%
Equity in (Earnings) of Affiliates
    (625 )     (219 )     (406 )     (185.4 )%
General & Administrative
    7,734       3,706       4,028       108.7  %
Depreciation, Depletion & Amortization
    8,987       8,112       875       10.8  %
Interest Expense
    2             2       100.0  %
 
                         
Total Costs and Expenses
  $ 60,532     $ 83,442     $ (22,910 )     (27.5 )%
 
                         
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    13.7       11.2       2.5       22.3 %
Average Lifting Costs (per Mcf)
  $ 0.51     $ 0.57     $ (0.06 )     (10.5) %
     Due to increased volumes, lifting costs per unit sold decreased $0.06 per Mcf in the period to period comparison, including $0.04 per Mcf due to lower well maintenance costs. Efficiencies in the water collection infrastructure are also being realized subsequent to the improvements that were made in the prior year. Additionally, property taxes and other miscellaneous items have decreased on a per unit basis as a result of the increased production period to period. These improvements are partially offset by increased severance taxes resulting from a higher realized sales price.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    13.7       11.2       2.5       22.3 %
Average Gathering and Compression Costs (per Mcf)
  $ 1.10     $ 0.93     $ 0.17       18.3 %
     The increase in gathering and compression costs was attributable to an additional $0.10 per Mcf charge for the purchase of firm transportation capacity on the TCO interstate pipeline. This was acquired to ensure deliverability of our gas as a result of increased demand for pipeline access in the 2006 period. Due to the application of EITF 04-13, the combining of matching buy/sell transactions accounts for an additional $0.11 per Mcf increase in the current period. Although the net costs associated with similar buy/sell transactions were incurred during the prior period, they were not recorded as part of gathering and compression costs. Instead, they were recorded on a gross basis as purchased gas sales and purchased gas costs. Gathering and compression costs have also increased approximately $0.05 per Mcf due to additional power expenses related to both increased megawatt hour rates charged by the power company and the conversion of several compressors from gas powered to electric powered towards the end of the prior year. Due to the increased production period to period, gathering

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and compression per unit costs improved $0.09 per Mcf as a result of decreases in maintenance and various other related activities.
                                 
                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    1.9       1.6       0.3       18.8 %
Average Cost (per Mcf)
  $ 5.52     $ 4.39     $ 1.13       25.7 %
     Included in royalty interest gas costs are the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. Although average market prices period to period are relatively flat, the increase in average cost per unit is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, where a large portion of production was locked in at prices lower than the current period market prices. Volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Purchased Gas Sales Volumes (Bcf)
    1.4       6.4       (5.0 )     (78.1 )%
Average Purchased Gas Costs (per Mcf)
  $ 6.94     $ 7.13     $ (0.19 )     (2.7 )%
     Included in purchased gas costs are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on TCO pipeline in order to satisfy obligations to certain customers. In accordance with EITF 99-19, we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 in the current period, purchased gas sales and volumes have decreased. EITF 04-13 allows for the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. The net result for transactions that meet the above criteria are reflected in transportation expense in the current year. Additionally, there are low volumes of gas we purchase from third party producers at market prices less our gathering charge.
     Other costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Well Site General Maintenance
  $ 920     $ 779     $ 141       18.1  %
Gob Gas Collection Costs
    695       708       (13 )     (1.8 )%
Miscellaneous
    527       143       384       268.5  %
Land Related
    343       226       117       51.8  %
Imbalance
    (450 )     (40 )     (410 )     (1,025.0 )%
Accounts Receivable Securitization Fees
          520       (520 )     (100.0 )%
 
                         
Total Other Costs and Expenses
  $ 2,035     $ 2,336     $ (301 )     (12.9 )%
 
                         
     Well site general maintenance costs increased in 2006 due to additional wells being drilled as part of the on-going drilling program.
     Gob gas collection costs decreased in 2006 due to the idling of an affiliated mine, which reduced the amount of gob collection required.
     Miscellaneous costs and expenses increased primarily due to various other transactions that occurred in both periods, none of which were individually material.
     Land related costs have increased in 2006 due to the related costs of additional brokers hired to accelerate our land right of ways and permitting activities in order to secure additional well and pipeline sites in advance of drilling.
     The value of the gas imbalance has shifted because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers. CNX Gas is responsible for monitoring this imbalance and we adjust to contracted volumes as circumstances warrant. This decrease in imbalance cost was offset by corresponding decreases in gas sales revenue.

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     Prior to separation from CONSOL Energy in August 2005, CNX Gas sold eligible receivables to a CONSOL Energy subsidiary on a discounted basis. The accounts receivable securitization fees in the prior period represent the discounted portion on the sale of those receivables. CNX Gas is no longer part of this program as of the date of separation.
     Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 as follows:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Knox Energy
  $ (742 )   $ (269 )   $ (473 )     (175.8 )%
Coalfield Pipeline
    (59 )     (3 )     (56 )     (1,866.7 )%
Buchanan Generation
    176       53       123       232.1  %
 
                         
Total Equity in (Earnings) Loss of Affiliates
  $ (625 )   $ (219 )   $ (406 )     (185.4 )%
 
                         
     Knox Energy had higher earnings in 2006 compared to 2005 primarily due to higher realized prices and additional service revenue.
     Coalfield Pipeline had higher earnings in 2006 compared to 2005 due primarily to additional third party gathering revenues.
     Buchanan Generation’s losses were higher in 2006 compared to 2005 primarily due to the facility running for fewer hours in 2006 compared to 2005.
     General and administrative costs increased to $7,734 in 2006 from $3,706 in 2005 primarily due to the additional costs related to being a separate publicly traded company, additional legal expenses and increased staffing and service costs as a result of the separation of CNX Gas from CONSOL Energy.
     Depreciation, depletion and amortization have increased due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Production
  $ 5,830     $ 5,235     $ 595       11.4 %
Gathering
    3,157       2,877       280       9.7 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 8,987     $ 8,112     $ 875       10.8 %
 
                         
     The increase in production related depreciation, depletion and amortization was primarily due to the increase in production period to period. Rates are generally calculated using the net book value of assets at the end of the year divided by either proved or proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets coming on line in 2006.
     Income Taxes
                                 
                            Percentage
    2006   2005   Variance   Change
Earnings Before Income Taxes
  $ 62,320     $ 27,630     $ 34,690       125.6 %
Tax Expense
  $ 24,167     $ 10,638     $ 13,529       127.2 %
Effective Income Tax Rate
    38.8 %     38.5 %     0.3 %        
     CNX Gas’ effective tax rate increased in 2006 primarily due to a slight increase in the net effect of state income taxes.

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Results of Operations
Six Months Ended June 30, 2006 compared with Six Months Ended June 30, 2005
(Amounts reported in thousands)
Net Income
     Net income changed primarily due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 193,987     $ 121,197     $ 72,790       60.1 %
Related Party Sales
    3,034       3,399       (365 )     (10.7) %
Royalty Interest Gas Sales
    28,493       18,742       9,751       52.0 %
Purchased Gas Sales
    32,130       69,257       (37,127 )     (53.6) %
Other Income
    13,431       4,527       8,904       196.7 %
 
                         
Total Revenue and Other Income
    271,075       217,122       53,953       24.8 %
Costs and Expenses:
                               
Lifting Costs
    14,695       12,180       2,515       20.6 %
Gathering and Compression Costs
    26,991       19,222       7,769       40.4 %
Royalty Interest Gas Costs
    23,683       14,463       9,220       63.7 %
Purchased Gas Costs
    32,751       70,086       (37,335 )     (53.3) %
Other
    3,864       5,594       (1,730 )     (30.9) %
Equity in (Earnings) Loss of Affiliates
    (772 )     132       (904 )     (684.8) %
General and Administrative
    14,706       7,472       7,234       96.8 %
Depreciation, Depletion and Amortization
    17,891       17,212       679       3.9 %
Interest Expense
    9             9       100.0 %
 
                         
Total Costs and Expenses
    133,818       146,361       (12,543 )     (8.6) %
 
                         
Earnings Before Income Taxes
    137,257       70,761       66,496       94.0 %
Income Taxes
    53,228       27,243       25,985       95.4 %
 
                         
Net Income
  $ 84,029     $ 43,518     $ 40,511       93.1 %
 
                         
     Net income for 2006 was improved primarily due to additional production and increased average sales prices, while also managing costs. The increased revenues were offset, in part, by higher costs attributable to production taxes, firm transportation charges and general and administrative charges.
Revenue and Other Income
     Revenue and other income increased due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 193,987     $ 121,197     $ 72,790       60.1 %
Related Party Sales
    3,034       3,399       (365 )     (10.7) %
Royalty Interest Gas Sales
    28,493       18,742       9,751       52.0 %
Purchased Gas Sales
    32,130       69,257       (37,127 )     (53.6) %
Other Income
    13,431       4,527       8,904       196.7 %
 
                         
Total Revenue and Other Income
    271,075       217,122       53,953       24.8 %
 
                         

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     The increase in revenue was primarily due to additional production and a higher average sales price per thousand cubic feet in 2006 compared to 2005.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    27.3       23.5       3.8       16.2 %
Average Sales Price (per Mcf)
  $ 7.22     $ 5.31     $ 1.91       36.0 %
     The increase in average sales price is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, where a large portion of production was locked in at prices lower than the current period market prices. Periodically, CNX Gas enters into physical fixed price gas supply transactions with both gas marketers and end users for terms varying in length. CNX Gas also enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. For the six months ended June 30, 2006, these physical and financial hedges represented approximately 8.3 Bcf of our gas sales volumes at an average price of $7.35 per Mcf, compared to approximately 19.3 Bcf at an average price of $4.94 per Mcf for the six months ended June 30, 2005. Sales volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    3.7       3.4       0.3       8.8 %
Average Sales Price (per Mcf)
  $ 7.71     $ 5.59     $ 2.12       37.9 %
     Included in royalty interest gas sales are the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in average sales price is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, where a large portion of production was locked in at prices lower than the current period market prices. Sales volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Purchased Gas Sales Volumes (Bcf)
    4.0       10.2       (6.2 )     (60.8) %
Average Sales Price (per Mcf)
  $ 8.11     $ 6.77     $ 1.34       19.8 %
     Included in purchased gas sales revenue are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on TCO pipeline in order to satisfy obligations to certain customers. In accordance with EITF 99-19, we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 in the current period, purchased gas sales and volumes have decreased. EITF 04-13 allows for the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. The net result for transactions that meet the above criteria are reflected in transportation expense in the current year. Additionally, there are low volumes of gas we purchase from third party producers at market prices less our gathering charge, which we then resell.
     Other income consists of insurance settlements, royalty income, third party gathering revenue, interest income and other miscellaneous income:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Insurance Proceeds
  $ 6,967     $     $ 6,967       100.0 %
Royalty Income
    4,578       3,901       677       17.4 %
Interest Income
    1,098             1,098       100.0 %
Third Party Gathering Revenue
    666       500       166       33.2 %
Other Miscellaneous
    122       126       (4 )     (3.2) %
 
                         
Total Other Income
  $ 13,431     $ 4,527     $ 8,904       196.7 %
 
                         
     The insurance settlements component of other income consists of business interruption insurance settlements related to a CONSOL Energy mine incident in 2005 which negatively impacted our gas production in that year. Additional settlements may be forthcoming pending final resolution of the claim.

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     Royalty income received from third parties is calculated as a percentage of the third parties’ sales price. Royalty income increased slightly in 2006 compared to 2005 as average gas market prices have also increased slightly period to period.
     Interest income increased in 2006, as a result of CNX Gas retaining cash collections as a separate stand alone company. As of the June 30, 2005, CNX Gas was still part of CONSOL Energy and retained no cash resulting in zero interest income.
     Third party gathering revenue has increased due to additional volumes being transported through our gathering systems in 2006 compared to 2005.
     Other miscellaneous income decreased due to various transactions, none of which are individually material throughout both periods.
Costs and Expenses
     Overall, costs and expenses decreased in 2006 primarily due to lower purchased gas costs. However, our operating costs and expenses increased in 2006 and are made up of the following components:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Costs and Expenses:
                               
Lifting Costs
  $ 14,695     $ 12,180     $ 2,515       20.6 %
Gathering and Compression Costs
    26,991       19,222       7,769       40.4 %
Royalty Interest Gas Costs
    23,683       14,463       9,220       63.7 %
Purchased Gas Costs
    32,751       70,086       (37,335 )     (53.3) %
Other
    3,864       5,594       (1,730 )     (30.9) %
Equity in (Earnings) Loss of Affiliates
    (772 )     132       (904 )     (684.8) %
General & Administrative
    14,706       7,472       7,234       96.8 %
Depreciation, Depletion & Amortization
    17,891       17,212       679       3.9 %
Interest Expense
    9             9       100.0 %
 
                         
Total Costs and Expenses
  $ 133,818     $ 146,361     $ (12,543 )     (8.6) %
 
                         
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    27.3       23.5       3.8       16.2 %
Average Lifting Costs (per Mcf)
  $ 0.54     $ 0.52     $ 0.02       3.8 %
     Lifting costs per unit sold increased $0.02 per Mcf in the period to period comparison, of which $0.05 per Mcf was due to higher production taxes in 2006 driven by higher realized sales price. Increased production resulted in decreased unit costs for well related maintenance, property taxes, and various other transactions, none of which were individually material, partially offsetting the overall increase in per unit lifting costs.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    27.3       23.5       3.8       16.2 %
Average Gathering and Compression Costs (per Mcf)
  $ 0.99     $ 0.82     $ 0.17       20.7 %
     The increase in gathering and compression costs was attributable to an additional $0.08 per Mcf charge for the purchase of firm transportation capacity on the TCO interstate pipeline. This was acquired to ensure deliverability of our gas as a result of increased demand for pipeline access in the 2006 period. Due to the application of EITF 04-13, the combining of matching buy/sell transactions accounts for an additional $0.08 per Mcf increase in the current period. Although the net costs associated with similar buy/sell transactions were incurred during the prior period, they were not recorded as part of gathering and compression costs. Instead, they were recorded on a gross basis as purchased gas sales and purchased gas costs. Gathering and compression costs have also increased approximately $0.01 per Mcf due to additional power expenses related to both increased megawatt hour rates charged by the power company and the conversion of several compressors from gas powered to electric powered towards the end of the prior year. Gathering and compression unit costs also fluctuated due to various other maintenance related activities, none of which were individually material.

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                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    3.7       3.4       0.3       8.8 %
Average Cost (per Mcf)
  $ 6.41     $ 4.32     $ 2.09       48.4 %
     Included in royalty interest gas costs are the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. Although average market prices period to period are relatively flat, the increase in average cost per unit is the result of CNX Gas exposing a larger portion of sales volumes to prevailing market prices in the current period compared to the prior period, where a large portion of production was locked in at prices lower than the current period market prices. Volumes increased as a result of additional wells coming online from our on-going drilling program.
                                 
                            Percentage
    2006   2005   Variance   Change
Purchased Gas Cost Volumes (Bcf)
    4.0       10.2       (6.2 )     (60.8 )%
Average Purchased Gas Costs (per Mcf)
  $ 8.27     $ 6.85     $ 1.42       20.7  %
     Included in purchased gas costs are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia Gas Transmission Corporation (TCO) pipeline in order to satisfy obligations to certain customers. In accordance with EITF 99-19, we have historically recorded our revenues and our costs on a gross basis. EITF 04-13 now allows for the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. As a result, purchased gas sales and volumes decreased in the six month period. The net result for transactions that meet the above criteria are reflected in transportation expense in the current period. Additionally, there are low volumes of gas we purchase from third party producers at market prices less our gathering charge.
     Other costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Well Site General Maintenance
  $ 1,800     $ 1,550     $ 250       16.1  %
Gob Gas Collection Costs
    1,384       1,416       (32 )     (2.3 )%
Land Related
    586       465       121       26.0  %
Capital Stock & Franchise Tax
    273       125       148       118.4  %
Miscellaneous
    692       65       627       964.6  %
Imbalance
    (871 )     844       (1,715 )     (203.2 )%
Accounts Receivable Securitization Fees
          1,129       (1,129 )     (100.0 )%
 
                         
Total Other Costs and Expenses
  $ 3,864     $ 5,594     $ (1,730 )     (30.9 )%
 
                         
     Well site general maintenance costs increased in 2006 due to additional wells being drilled as part of the on-going drilling program.
     Gob gas collection costs decreased in 2006 due to the idling of an affiliated mine, which reduced the amount of gob collection required.
     Land related costs have increased in 2006 due to the additional brokers hired to accelerate our land right of ways and permitting activities in order to secure additional well and pipeline sites in advance of drilling.
     Capital stock and franchise taxes have increased in 2006 due to the additional net income compared to the 2005 period.
     Miscellaneous costs and expenses increased primarily due to various other transactions that occurred in both periods, none of which were individually material.
     The value of the gas imbalance has shifted because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers. CNX Gas is responsible for monitoring this imbalance and we adjust to contracted volumes as circumstances warrant. This decrease in imbalance cost was offset by corresponding decreases in gas sales revenue.

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     Prior to separation from CONSOL Energy in August 2005, CNX Gas sold eligible receivables to a CONSOL Energy subsidiary on a discounted basis. The accounts receivable securitization fees in the prior period represent the discounted portion on the sale of those receivables. CNX Gas is no longer part of this program as of the date of separation.
     Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 as follows:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Knox Energy
  $ (1,166 )   $ 8     $ (1,174 )     (14,675.0 )%
Coalfield Pipeline
    (4 )     (19 )     15       78.9  %
Buchanan Generation
    398       143       255       178.3  %
 
                         
Total Equity in (Earnings) Loss of Affiliates
  $ (772 )   $ 132     $ (904 )     (684.8 )%
 
                         
     Knox Energy had earnings in 2006 compared to a loss in 2005 primarily due to higher realized prices and additional service revenue.
     Coalfield Pipeline had lower earnings in 2006 compared to 2005 primarily due to pipeline downtime as a result of upgrading and maintaining the main compressor and an interstate pipeline maintenance related curtailment.
     Buchanan Generation’s losses were higher in 2006 compared to 2005 primarily due to the facility running for fewer hours in 2006 compared to 2005.
     General and administrative costs increased to $14,706 in 2006 from $7,472 in 2005 primarily due to the additional costs related to being a separate publicly traded company, additional legal expenses and increased staffing and service costs as a result of the separation of CNX Gas from CONSOL Energy.
     Depreciation, depletion and amortization have increased due to the following items:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Production
  $ 11,645     $ 11,458     $ 187       1.6 %
Gathering
    6,246       5,754       492       8.6 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 17,891     $ 17,212     $ 679       3.9 %
 
                         
     The increase in production related depreciation, depletion and amortization was primarily due to the increase in production period to period. Rates are generally calculated using the net book value of assets at the end of the year divided by either proved or proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets coming on line in 2006.
     Income Taxes
                                 
                            Percentage
    2006   2005   Variance   Change
Earnings Before Income Taxes
  $ 137,257     $ 70,761     $ 66,496       94.0 %
Tax Expense
  $ 53,228     $ 27,243     $ 25,985       95.4 %
Effective Income Tax Rate
    38.8 %     38.5 %     0.3 %        
     CNX Gas’ effective tax rate increased in 2006 primarily due to a slight increase in the net effect of state income taxes.
Liquidity and Capital Resources
     We intend to satisfy our future working capital requirements and fund our capital expenditures with cash from operations and if necessary, our $200,000 credit facility. The credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital.
     CNX Gas and our subsidiaries guarantee CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the

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indenture and the agreement governing CONSOL Energy’s 8.25% medium term notes in the amount of $45,000 would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes.
     We believe that cash generated from operations and borrowings under our credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures other than major acquisitions, and to provide required financial resources for the foreseeable future. Nevertheless, our ability to satisfy our working capital requirements or fund planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the gas industry and other financial and business factors, some of which are beyond our control.
     We have also entered into various gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net loss of $14,973, net of $8,899 of deferred tax at June 30, 2006. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings in the six months ended June 30, 2006.
     Cash Flows (in thousands)
                         
    Year to Date   Year to Date    
    2006   2005   Change
Cash provided by operating activities
  $ 126,833     $ 81,763     $ 45,070  
Cash used in investing activities
  $ (82,905 )   $ (39,404 )   $ (43,501 )
Cash provided by (used in) financing activities
  $ 306     $ (42,362 )   $ 42,668  
Cash provided by operating activities increased significantly as a result of additional earnings before income taxes as previously discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Operating cash flows were also improved due to various changes in working capital throughout both periods.
Cash used in investing activities increased primarily due to our expanded capital program.
A bank overdraft, due to the timing of fund transfers between accounts, resulted in cash provided by financing activities in the current period. The prior period balance represents the net effect of all cash transactions done at the parent company level prior to separation.
     Contractual Commitments
     The following is a summary of our significant contractual obligations at June 30, 2006. We estimate payments, net of any applicable reimbursements, related to these items at June 30, 2006 to be as follows:
                                         
            Within     1-3     3-5     More than  
(In thousands)   Total     1 Year     Years     Years     5 Years  
Long Term Debt Obligations
  $     $     $     $     $  
Capital (Finance) Lease Obligations
    67,090       6,952       12,345       10,815       36,978  
Operating Lease Obligations
    4,398       907       1,325       1,325       841  
Other Long-Term Liabilities:
                                       
Gas Firm Transportation Obligation
    19,652       3,431       6,772       5,843       3,606  
Other Liabilities (a)
    13,248                         13,248  
Well Plugging Liabilities
    8,328       378       756       756       6,438  
Pension
    332       1       8       35       288  
Postretirement Benefits Other than Pension
    3,357       5       44       104       3,204  
 
                             
Total Contractual Obligations
  $ 116,405     $ 11,674     $ 21,250     $ 18,878     $ 64,603  
 
                             
 
(a)   This item represents legal contingencies reflected on the balance sheet for potential settlements for two of the cases referenced in Note 7 of our quarterly financial statements. Due to the uncertainty surrounding these settlements, it is difficult to predict if and when a payout may take place.
     Off-Balance Sheet Transactions
     We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are likely to have a material current or future effect on our condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the consolidated financial statements.

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FORWARD-LOOKING STATEMENTS
     We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
    our business strategy;
 
    our financial position;
 
    our cash flow and liquidity;
 
    declines in the prices we receive for our gas affecting our operating results and cash flow;
 
    uncertainties in estimating our gas reserves;
 
    replacing our gas reserves;
 
    uncertainties in exploring for and producing gas;
 
    our inability to obtain additional financing necessary in order to fund our operations, capital expenditures and to meet our other obligations;
 
    disruptions, capacity constraints in or other limitations on the pipeline systems which deliver our gas;
 
    competition in the gas industry;
 
    the availability of personnel and equipment;
 
    increased costs;
 
    our inability to retain and attract key personnel;
 
    our joint venture arrangements;
 
    the effects of government regulation and permitting and other legal requirements;
 
    legal uncertainties relating to the ownership of CBM;
 
    costs associated with perfecting title for gas rights in some of our properties;
 
    our need to use unproven technologies to extract CBM in some properties;
 
    our relationships and arrangements with CONSOL Energy; and
 
    other factors discussed under “Risk Factors” in the 10-K for the year ended December 31, 2005.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     In addition to the risks inherent in our operations, CNX Gas is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CNX Gas’ exposure to the risks of changing natural gas prices.
     CNX Gas uses fixed-price contracts and derivative commodity instruments that qualify as cash-flow hedges under Statement of Financial Accounting Standards No. 133, as amended, to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy strictly prohibits the use of derivatives for speculative purposes.
     CNX Gas has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from our asset base. All of the derivative instruments are held for purposes other than trading.

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They are used primarily to reduce uncertainty and volatility and cover underlying exposures. CNX Gas’ market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.
     CNX Gas believes that the use of derivative instruments, along with the risk assessment procedures and internal controls, does not expose CNX Gas to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CNX Gas’ results of operations depending on interest rates, exchange rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.
     For a summary of accounting policies related to derivative instruments, see Note 1 of the notes to the consolidated annual financial statements included in our Annual Report Form 10-K for the year ended December 31, 2005.
     Sensitivity analyses of the incremental effects on pre-tax income for the six months ended June 30, 2006 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of June 30, 2006 are provided in the following table:
                 
    Incremental Decrease in Pre-tax Income Assuming a
    Hypothetical Price Change of:
    10%   25%
    (In millions)
Natural Gas (1)
  $ 20.0     $ 46.9  
 
(1)   CNX Gas remains at risk for possible changes in the market value of these derivative instruments, however, such risk should be reduced by price changes in the underlying hedged item. The effect of this offset is not reflected in the sensitivity analyses. CNX Gas entered into derivative instruments to convert the market prices related to portions of the 2006 through 2008 anticipated sales of natural gas to fixed prices. The sensitivity analyses reflect an inverse relationship between increases in commodity prices and a benefit to earnings. When commodity prices increase, pretax income decreases. As of June 30, 2006, the fair value of these contracts was a net loss of $14,973, net of $8,899 deferred tax. We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.
Hedging Volumes
As of June 30, 2006, our hedged volumes for the periods indicated are as follows:
                                         
    Three Months   Three Months   Three Months   Three Months    
    Ended   Ended   Ended   Ended    
    March 31   June 30   September 30   December 31   Total Year
2006 Fixed Price Volumes
                                       
Hedged Mcf
    3,654,822       4,619,289       4,670,051       4,050,761       16,994,923  
Weighted Average Hedge Price/Mcf
  $ 6.88     $ 7.73     $ 7.73     $ 7.21     $ 7.42  
 
                                       
2007 Fixed Price Volumes
                                       
Hedged Mcf
    1,827,411       1,847,716       1,868,020       1,868,020       7,411,167  
Weighted Average Hedge Price/Mcf
  $ 7.67     $ 7.67     $ 7.67     $ 7.67     $ 7.67  
 
                                       
2008 Fixed Price Volumes
                                       
Hedged Mcf
    1,847,716       1,847,716       1,868,020       1,868,020       7,431,472  
Weighted Average Hedge Price/Mcf
  $ 7.20     $ 7.20     $ 7.20     $ 7.20     $ 7.20  
     CNX Gas is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review.
     All CNX Gas transactions are denominated in U.S. dollars, and, as a result, we do not have material exposure to currency exchange-rate risks.

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ITEM 4. CONTROLS AND PROCEDURES
               Evaluation of Disclosure Controls and Procedures
     CNX Gas, under the supervision and with the participation of its management, including the Company’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our principal executive officer and principal financial officer have concluded that CNX Gas’ disclosure controls and procedures are effective as of June 30, 2006 to ensure that information required to be disclosed by CNX Gas in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports 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.
               Changes in Internal Controls Over Financial Reporting.
     There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
     The second through sixth paragraphs of Note 7 — Commitments and Contingent Liabilities in the notes to the Consolidated Financial Statements included in Part I of this Form 10-Q are incorporated herein by reference.
ITEM 1A. RISK FACTORS
     No material changes from our most recently filed Annual Report on Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
     None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
   a) The Annual Meeting of Stockholders was held on April 28, 2006.
   b) Brief description of matters voted upon:
  (i)   Elected the following persons to serve as directors for a one-year term expiring at the company’s annual meeting of stockholders in 2007 as follows:
                 
Director   Shares Voted For   Shares Withheld
Philip W. Baxter
    147,605,853       618,053  
James E. Altmeyer, Sr.
    146,785,653       1,438,253  
Nicholas J. DeIuliis
    146,714,758       1,509,148  
William J. Lyons
    142,684,718       5,539,188  
Raj K. Gupta
    147,605,853       618,053  
J. Brett Harvey
    142,684,518       5,539,388  
John R. Pipski
    147,605,653       618,253  
  (ii)   Ratified the selection of PricewaterhouseCoopers LLP, as independent registered public accounting firm for the year ended December 31, 2006. The vote was 148,163,828 votes for ratification and 53,804 votes against ratification.
ITEM 5. OTHER INFORMATION
     None
ITEM 6. EXHIBITS
  10.1   Firm Transportation Agreement, dated as of April 27th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC.
 
  10.2   Firm Lateral Transportation Agreement, dated as of April 27th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC.
 
  10.3   The summary description of the base compensation and short-term incentive opportunities for the executive officers of CNX Gas for 2006 is incorporated herein by reference from Item 1.01 of the Current Report on Form 8-K filed by the CNX Gas on May 1, 2006. *
 
  10.4   The initial election grant of options to purchase common stock of CNX Gas to Joseph T. Williams, upon his election to the Board of Directors on July 10, 2006, is incorporated herein by reference from Item 1.01 of the Current Report on Form 8-K filed by CNX Gas on July 11, 2006.
 
  31.1   Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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  31.2   Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
  32.1   Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
  32.2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
 
*   Management compensatory contract or arrangement.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
     Dated: August 2, 2006
             
 
           
    CNX Gas Corporation    
 
           
 
  By:   /s/ Nicholas J. DeIuliis    
 
           
 
      Nicholas J. DeIuliis    
 
      President and Chief Executive Officer    
 
      (Duly Authorized Officer)    
 
           
 
  By:   /s/ Gary J. Bench    
 
           
 
      Gary J. Bench    
 
      Senior Vice President and Chief Financial Officer    
 
      (Principal Financial Officer)    

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EXHIBIT INDEX
     
10.1
  Firm Transportation Agreement, dated as of April 27th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC.
 
   
10.2
  Firm Lateral Transportation Agreement, dated as of April 27th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC.
 
   
10.3
  The summary description of the base compensation and short-term incentive opportunities for the executive officers of CNX Gas for 2006 is incorporated herein by reference from Item 1.01 of the Current Report on Form 8-K filed by the CNX Gas on May 1, 2006. *
 
   
10.4
  The initial election grant of options to purchase common stock of CNX Gas to Joseph T. Williams, upon his election to the Board of Directors on July 10, 2006, is incorporated herein by reference from Item 1.01 of the Current Report on Form 8-K filed by CNX Gas on July 11, 2006.
 
   
31.1
  Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
31.2
  Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32.1
  Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
   
32.2
  Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
 
*   Management compensatory contract or arrangement.

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