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CNX Gas 10-Q 2006

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.2
  6. Ex-32.2
CNX Gas Corporation 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 September 30, 2006
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     
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 September 30, 2006 is 150,864,075 shares.
 
 

 


 

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 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 nine months ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Revenue and Other Income:
                               
Outside Sales
  $ 92,507     $ 71,681     $ 286,494     $ 192,878  
Related Party Sales
    2,719       1,926       5,753       5,325  
Royalty Interest Gas Sales
    13,221       12,317       41,714       31,059  
Purchased Gas Sales
    9,076       88,288       41,206       157,545  
Other Income
    6,044       2,100       19,475       6,627  
 
                       
Total Revenue and Other Income
    123,567       176,312       394,642       393,434  
Costs and Expenses:
                               
Lifting Costs
    7,295       6,907       21,990       19,087  
Gathering and Compression Costs
    13,949       10,696       40,940       29,918  
Royalty Interest Gas Costs
    10,808       10,042       34,491       24,505  
Purchased Gas Costs
    9,340       89,653       42,091       159,739  
Other
    2,265       2,741       6,138       8,335  
Equity in (Earnings) Loss of Affiliates
    45       88       (727 )     220  
General and Administrative
    8,522       4,699       23,228       12,171  
Depreciation, Depletion and Amortization
    9,546       8,671       27,437       25,883  
 
                       
Total Costs and Expenses
    61,770       133,497       195,588       279,858  
 
                       
Earnings Before Income Taxes
    61,797       42,815       199,054       113,576  
Income Taxes
    24,204       16,745       77,432       43,988  
 
                       
Net Income
  $ 37,593     $ 26,070     $ 121,622     $ 69,588  
 
                       
Earnings Per Share:
                               
 
                               
Basic
  $ 0.25     $ 0.19     $ 0.81     $ 0.54  
 
                       
Diluted
  $ 0.25     $ 0.19     $ 0.81     $ 0.54  
 
                       
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,850,930       139,294,276       150,839,264       128,422,601  
 
                       
Dilutive
    151,029,192       139,416,414       150,998,713       128,499,081  
 
                       
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)        
    September 30,     December 31,  
    2006     2005  
ASSETS
               
Current Assets:
               
Cash and Cash Equivalents
  $ 107,576     $ 20,073  
Accounts Receivable:
               
Trade
    33,016       41,121  
Related Party
    671       728  
Other
    1,347       550  
Derivatives
    6,848        
Deferred Taxes
          9,339  
Other Current Assets
    23,392       18,067  
 
           
Total Current Assets
    172,850       89,878  
Property, Plant and Equipment, Net
    811,214       723,547  
Other Assets
    11,114       11,903  
Investments in Equity Affiliates
    51,658       49,528  
 
           
TOTAL ASSETS
  $ 1,046,836     $ 874,856  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities:
               
Accounts Payable
  $ 18,686     $ 22,541  
Accrued Royalties Payable
    12,842       10,504  
Accrued Severance Taxes
    2,017       2,747  
Accrued Income Taxes
    6,591       5,518  
Derivatives
          23,777  
Deferred Taxes
    2,671        
Other Current Liabilities
    26,130       21,071  
 
           
Total Current Liabilities
    68,937       86,158  
Deferred Taxes
    103,540       47,736  
Other Liabilities
    17,783       14,310  
Well Plugging Liabilities
    8,723       10,908  
Derivatives
    6,328       32,909  
Postretirement Benefits Other Than Pension
    3,337       3,363  
 
           
Total Liabilities
    208,648       195,384  
 
           
Stockholders’ Equity
               
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,864,075 Issued and Outstanding at September 30, 2006 and December 31, 2005
    1,508       1,508  
Capital in Excess of Par Value
    780,304       779,509  
Retained Earnings (Deficit)
    56,092       (65,530 )
Accumulated Other Comprehensive Income (Loss)
    284       (34,733 )
Unearned Compensation on Restricted Stock Units
          (1,282 )
 
           
Total Stockholders’ Equity
    838,188       679,472  
 
           
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 1,046,836     $ 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     Unearned        
            Capital in     Retained     Other     Compensation     Total  
    Common     Excess of     Earnings/     Comprehensive     on Restricted     Stockholders’  
    Stock     Par Value     (Deficit)     Income (Loss)     Stock Units     Equity  
Balance at December 31, 2005
  $ 1,508     $ 779,509     $ (65,530 )   $ (34,733 )   $ (1,282 )   $ 679,472  
Net Income
                121,622                   121,622  
Gas Cash Flow Hedge (Net of ($22,469) tax)
                      35,017             35,017  
 
                                   
Comprehensive Income (a)
                121,622       35,017             156,639  
Elimination of Unearned Compensation on Restricted Stock Units
          (1,282 )                 1,282        
Amortization of Restricted Stock Unit Grants
          654                         654  
Amortization of Stock Based Compensation Awards
          1,423                         1,423  
 
                                   
Balance at September 30, 2006
  $ 1,508     $ 780,304     $ 56,092     $ 284     $     $ 838,188  
 
                                   
 
(a)   Of the $35,017 net change in accumulated other comprehensive income in the period, $7,670 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 September 30, 2005 was $50,299.
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 nine months ended  
    September 30,  
    2006     2005  
Operating Activities:
               
Net Income
  $ 121,622     $ 69,588  
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
               
Depreciation, Depletion and Amortization
    27,437       25,883  
Stock Based Compensation
    2,077        
Deferred Income Taxes
    45,345       32,948  
Equity in (Earnings) Loss of Affiliates
    (727 )     220  
Changes in Operating Assets:
               
Accounts Receivable
    7,308       (36,281 )
Related Party Receivable
    57          
Other Current Assets
    (161 )     (2,710 )
Changes in Other Assets
    845       4,374  
Changes in Operating Liabilities:
               
Accounts Payable
    (3,855 )     10,297  
Income Taxes
    1,073       11,040  
Other Current Liabilities
    758       9,325  
Changes in Other Liabilities
    3,690       63  
Other
    474       149  
 
           
Net Cash Provided by Operating Activities
    205,943       124,896  
 
           
Investing Activities:
               
Capital Expenditures
    (117,037 )     (70,207 )
Investment in Equity Affiliates
    (1,403 )     (2,697 )
 
           
Net Cash Used in Investing Activities
    (118,440 )     (72,904 )
 
           
Financing Activities:
               
Issuance of Common Stock
          420,167  
Dividends Paid
          (420,167 )
Payments to Parent
          (22,439 )
 
           
Net Cash Used in Financing Activities
          (22,439 )
Net Increase in Cash and Cash Equivalents
    87,503       29,553  
Cash and Cash Equivalents at Beginning of Period
    20,073       3  
 
           
Cash and Cash Equivalents at End of Period
  $ 107,576     $ 29,556  
 
           
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 nine month periods ended September 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 nine months ended September 30, 2006 classifications.
     Effective January 1, 2006, CNX Gas adopted Emerging Issues Task Force 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 $35,074 of revenue and $35,929 of expense in the three months ended September 30, 2006 and $95,579 of revenue and $98,615 of expense in the nine months ended September 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 nine months ended September 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 Financial Statements for a further discussion on stock-based compensation.

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     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 were used to acquire shares of common stock at the average market price during the reporting period.
     The computations for basic and diluted earnings per share are as follows:
                                 
    For the three months ended     For the nine months ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Net Income
  $ 37,593     $ 26,070     $ 121,622     $ 69,588  
 
                       
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,850,930       139,294,276       150,839,264       128,422,601  
Effect of stock based compensation
    178,262       122,138       159,449       76,480  
 
                       
Dilutive
    151,029,192       139,416,414       150,998,713       128,499,081  
 
                       
Earnings per share:
                               
Basic
  $ 0.25     $ 0.19     $ 0.81     $ 0.54  
 
                       
Diluted
  $ 0.25     $ 0.19     $ 0.81     $ 0.54  
 
                       
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 was further amended on October 11, 2006, the company adopted a Long-Term Incentive Program under the company’s Equity Incentive Plan, as amended. 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, as well as cash awards. The total number of shares of CNX Gas common stock with respect to which stock awards may be granted under the CNX Gas Equity Incentive Plan is 2,500,000.
     The total stock-based compensation expense was $874 and $2,077 for the three and nine months ended September 30, 2006 and the related deferred tax benefit totaled $338 and $804, respectively. Prior to January 1, 2006, CNX Gas accounted for stock-based compensation under the recognition and measurement provisions of Accounting Principles Board Opinion (APB) 25, “Accounting for Stock Issued to Employees,” as amended. 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 nine months ended September 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.

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     As a result of adopting SFAS 123R, pretax income and net income for the three months ended September 30, 2006 was $478 and $292 lower, respectively, than if we had continued to account for stock-based compensation under APB 25. Pretax income and net income for the nine months ended September 30, 2006 was $1,423 and $872 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 September 30, 2006 was less than $0.01 per share. Basic earnings per share for the nine months ended September 30, 2006 and diluted earnings per share for the three and nine months ended September 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 September 30, 2006, there were no options exercised.
     The pro forma table below reflects net earnings and basic and diluted earnings per share for the three and nine months ended September 30, 2005, had CNX Gas applied the fair value recognition provisions of SFAS 123:
                 
    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2005     2005  
Net income as reported
  $ 26,070     $ 69,588  
 
Add: Stock-based compensation expense for restricted stock units
    81       81  
 
Deduct: Total stock-based employee compensation expense determined under Black-Scholes option pricing model and stock-based compensation expense for restricted stock units
    (266 )     (266 )
 
Pro forma net income
  $ 25,885     $ 69,403  
 
Earnings per share:
               
 
Basic - as reported
  $ 0.19     $ 0.54  
 
Basic - Pro forma
  $ 0.19     $ 0.54  
 
Diluted - as reported
  $ 0.19     $ 0.54  
 
Diluted - pro forma
  $ 0.19     $ 0.54  
     As part of its SFAS 123R adoption, CNX Gas continues to use 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 nine months   For the nine months
    ended Sept. 30, 2006   ended Sept. 30, 2005
Weighted Average Fair Value of Grants
  $ 9.85     $ 5.34  
Risk Free Interest Rate
    4.65 %     4.24 %
Dividend Yield
           
Expected Volatility
    32.3 %     34.4 %
Expected life in years
    4.5       4.0  
     Option activity under the CNX Gas Equity Incentive Plan during the nine months ended September 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
    478,419       28.49              
Exercised
                       
Forfeited
    (28,835 )     18.87              
 
                             
Outstanding at September 30, 2006
    1,490,160     $ 19.99       9.08     $ 7,247  
 
                       
Vested and expected to vest at September 30, 2006
    1,490,160     $ 19.99       9.08     $ 7,247  
 
                       
Exercisable at September 30, 2006
    254,564     $ 16.05       8.84     $ 1,812  
 
                       
     These stock options will terminate ten years after the date on which they were granted. As of September 30, 2006 there are 1,467,930 shares of common stock underlying employee stock options outstanding covered by the Equity Incentive Plan adopted June 30, 2005. There are 1,018,354 employee stock options that vest 25% per year, beginning one year after the grant date and 449,576 employee stock options that vest 100%, three years after the grant date. There are 22,230 non-employee director stock options outstanding at September 30, 2006. Non-employee director stock options vest 33% per year, beginning one year after the grant date. 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 nine months ended September 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 September 30, 2006. This amount changes based on the fair market value of CNX Gas’ stock. The total pre-tax fair value of options vested was $1,359 for the three and nine months ended September 30, 2006.
     As of September 30, 2006, $9,075 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 2.63 years.

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     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 68,371 restricted stock units were outstanding at September 30, 2006, vesting over a weighted average remaining period of 1.96 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:
                 
            Weighted Average
    Number of Shares   Grant Date Fair Value
Nonvested at December 31, 2005
    92,969     $ 16.00  
Granted
    6,143       28.50  
Vested
    (30,741     16.00  
 
               
Nonvested at September 30, 2006
    68,371     $ 17.12  
 
               
Note 3—Pension and Other Postretirement Benefits:
     The components of net periodic benefit costs are as follows:
                                                                 
    For the three months     For the nine months  
    ended September 30,     ended September 30,  
    Pension     Other Benefits     Pension     Other Benefits  
    2006     2005     2006     2005     2006     2005     2006     2005  
Components of Net Periodic Benefit Costs:
                                                               
Service costs
  $ 70     $ 91     $ 23     $ 40     $ 210     $ 91     $ 69     $ 120  
Interest costs
    1       28       25       42       3       28       75       126  
Amortization of prior service costs credit
    (2 )           (43 )     (28 )     (6 )           (129 )     (84 )
Recognized net actuarial loss (gain)
    (3 )                 11       (9 )                 33  
 
                                               
Benefit costs
  $ 66     $ 119     $ 5     $ 65     $ 198     $ 119     $ 15     $ 195  
 
                                               
     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 postretirement benefit plan in 2006. We intend to pay benefit claims as they become due. For the three and nine months ended September 30, 2006, there were $25 and $41 in payments made pursuant to the other postretirement 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. CNX Gas made an initial contribution of $20 to the pension plan in the second quarter 2006. There were no contributions made in the third quarter 2006. Prior to separation, the pension obligations remained with CONSOL Energy. The 2005 periods represent obligations incurred by CNX Gas from the point of separation going forward.
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 nine months ended September 30,  
    2006     2005  
    Amount     Percent     Amount     Percent  
Statutory U.S. Federal Income Tax
  $ 69,669       35.0 %   $ 39,751       35.0 %
Net Effect of State Income Tax
    8,619       4.3 %     4,793       4.2 %
Other
    (856 )     (0.4 )%     (556 )     (0.5 )%
 
                       
Income Tax Expense/ Effective Rate
  $ 77,432       38.9 %   $ 43,988       38.7 %
 
                       

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     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 nine months ended September 30, 2006 and 2005 was calculated using the annual effective rate projection on recurring earnings.
Note 5—Property, Plant and Equipment:
                 
    September 30,     December 31,  
    2006     2005  
Surface Lands
  $ 34,171     $ 26,573  
Mineral Interests
    55,621       55,621  
Wells and Related Equipment
    164,377       141,959  
Intangible Drilling
    357,980       312,467  
Gathering Assets
    381,194       344,355  
Gas Well Plugging
    5,252       7,680  
Other
    5,480       36  
 
           
Total Property, Plant and Equipment
    1,004,075       888,691  
Accumulated Depreciation, Depletion and Amortization
    (192,861 )     (165,144 )
 
           
Property, Plant and Equipment, net
  $ 811,214     $ 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 September 30, 2006, the leverage ratio was met at September 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 September 30, 2006.
     At September 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 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 in 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 September 21, 2006, the plaintiffs filed an amended complaint in the Circuit Court of Buchanan County, Virginia (Case No. CL04-91) which, among other things, added CONSOL Energy, ICCC and CNX Gas Company LLC as additional defendants. The 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.

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     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 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. A hearing was held before a Court-appointed Special Master with regard to the scope of the asserted CDX patents and the Special Master’s report and recommendations was adopted by order of the Court on October 13, 2006. As a result of that order and subject to appellate review, certain of our wells may be found to infringe certain of the CDX patents in suit, if those patents are ultimately determined to be valid and enforceable. We continue to believe that we do not infringe any properly construed claim of any valid, enforceable patent. We cannot predict the ultimate 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 net proceeds. The audit is ongoing with no resolution being proposed by Buchanan County as of September 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, but could impact our results of operations and our 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. 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 2003, approximately $12,000 (including interest) to the group of royalty owners that brought the suit for the period from 1989 to 1999. A final payment was made to the plaintiffs in 2003 for approximately $5,600 to adjust all royalties owed to the plaintiffs from the date of the court ruling in 1999 forward to 2003, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of this lawsuit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various other royalty owners as a result of this 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 September 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
  $ 420     $ 420     $     $     $  
Other
    762       762                    
 
                             
Total Surety Bonds
  $ 1,182     $ 1,182     $     $     $  
Other:
                                       
Guarantees
  $ 11,000     $ 11,000     $     $     $  
 
                             
Total Guarantees
  $ 11,000     $ 11,000     $     $     $  
 
                             
Total Commitments
  $ 29,029     $ 29,029     $     $     $  
 
                             
     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. The 2005 segment information was reclassified to conform to the 2006 presentation. Certain segment assets, depreciation, depletion and amortization and capital expenditures previously reported within Central Appalachia and Tennessee and Northern Appalachia are now included in the Gathering segment.
     Industry segment results for the three months ended September 30, 2006 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 87,636     $ 4,871     $     $ 92,507     $     $ 92,507  
Sales—related parties
    2,699       20             2,719             2,719  
Sales—royalty interest gas
    13,202       19             13,221             13,221  
Sales—purchased gas
    9,076                   9,076             9,076  
Other revenue
    5,663       11       370       6,044             6,044  
Intersegment revenues
                15,464       15,464       (15,464 )      
 
                                   
Total Revenue and Other Income
  $ 118,276     $ 4,921     $ 15,834     $ 139,031     $ (15,464 )   $ 123,567  
 
                                   
Earnings Before Income Taxes
  $ 57,700     $ 300     $ 3,797     $ 61,797     $     $ 61,797  (A)
 
                                   
Segment assets
  $ 538,418     $ 36,117     $ 364,725     $ 939,260     $ 107,576     $ 1,046,836  (B)(C)
 
                                   
Depreciation, depletion and amortization
  $ 5,727     $ 590     $ 3,229     $ 9,546     $     $ 9,546  
 
                                   
Capital expenditures
  $ 20,741     $ 2,483     $ 10,804     $ 34,028     $     $ 34,028  
 
                                   
 
(A)   Includes equity in loss of unconsolidated affiliates of $45.
 
(B)   Includes investments in unconsolidated equity affiliates of $51,658.
 
(C)   The $107,576 represents cash which is not allocated to individual segments.

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     Industry segment results for the three months ended September 30, 2005 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 67,067     $ 4,614     $     $ 71,681     $     $ 71,681  
Sales—related parties
    1,908       18             1,926             1,926  
Sales—royalty interest gas
    12,267       50             12,317             12,317  
Sales—purchased gas
    88,288                   88,288             88,288  
Other revenue
    1,796       10       294       2,100             2,100  
Intersegment revenues
                12,424       12,424       (12,424 )      
 
                                   
Total Revenue and Other Income
  $ 171,326     $ 4,692     $ 12,718     $ 188,736     $ (12,424 )   $ 176,312  
 
                                   
Earnings Before Income Taxes
  $ 38,157     $ 471     $ 4,187     $ 42,815     $     $ 42,815  (D)
 
                                   
Segment assets
  $ 483,635     $ 14,880     $ 327,806     $ 826,321     $     $ 826,321  (E)
 
                                   
Depreciation, depletion and amortization
  $ 4,871     $ 813     $ 2,987     $ 8,671     $     $ 8,671  
 
                                   
Capital expenditures
  $ 19,394     $ 3,464     $ 10,707     $ 33,565     $     $ 33,565  
 
                                   
 
(D)   Central Appalachia and Tennessee segment includes equity in loss of unconsolidated affiliates of $88.
 
(E)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $49,850.
     Industry segment for the nine months ended September 30, 2006 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 270,138     $ 16,356     $     $ 286,494     $     $ 286,494  
Sales—related parties
    5,680       73             5,753             5,753  
Sales—royalty interest gas
    41,574       140             41,714             41,714  
Sales—purchased gas
    41,206                   41,206             41,206  
Other revenue
    18,401       38       1,036       19,475             19,475  
Intersegment revenues
                41,687       41,687       (41,687 )      
 
                                   
Total Revenue and Other Income
  $ 376,999     $ 16,607     $ 42,723     $ 436,329     $ (41,687 )   $ 394,642  
 
                                   
Earnings Before Income Taxes
  $ 183,369     $ 3,685     $ 12,000     $ 199,054     $     $ 199,054  (F)
 
                                   
Segment assets
  $ 538,418     $ 36,117     $ 364,725     $ 939,260     $ 107,576     $ 1,046,836  (G)(H)
 
                                   
Depreciation, depletion and amortization
  $ 16,218     $ 1,811     $ 9,408     $ 27,437     $     $ 27,437  
 
                                   
Capital expenditures
  $ 65,377     $ 14,987     $ 36,673     $ 117,037     $     $ 117,037  
 
                                   
 
(F)   Includes equity in earnings of unconsolidated affiliates of $727.
 
(G)   Includes investments in unconsolidated equity affiliates of $51,658.
 
(H)   The $107,576 represents cash which is not allocated to individual segments.

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     Industry segment results for the nine months ended September 30, 2005 are:
                                                 
    Central                                      
    Appalachia                             Corporate        
    and     Northern             Total     Adjustments &        
    Tennessee     Appalachia     Gathering     Gas     Eliminations     Consolidated  
Sales—outside
  $ 181,673     $ 11,205     $     $ 192,878     $     $ 192,878  
Sales—related parties
    5,280       45             5,325             5,325  
Sales—royalty interest gas
    30,953       106             31,059             31,059  
Sales—purchased gas
    157,545                   157,545             157,545  
Other revenue
    5,793       40       794       6,627             6,627  
Intersegment revenues
                35,596       35,596       (35,596 )      
 
                                   
Total Revenue and Other Income
  $ 381,244     $ 11,396     $ 36,390     $ 429,030     $ (35,596 )   $ 393,434  
 
                                   
Earnings Before Income Taxes
  $ 104,404     $ 415     $ 8,757     $ 113,576     $     $ 113,576 (I)
 
                                   
Segment assets
  $ 483,635     $ 14,880     $ 327,806     $ 826,321     $     $ 826,321 (J)
 
                                   
Depreciation, depletion and amortization
  $ 15,100     $ 1,846     $ 8,937     $ 25,883     $     $ 25,883  
 
                                   
Capital expenditures
  $ 41,766     $ 7,725     $ 20,716     $ 70,207     $     $ 70,207  
 
                                   
 
(I)   Central Appalachia and Tennessee segment includes equity in loss of unconsolidated affiliates of $220.
 
(J)   Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $49,850.
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.
     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (FAS 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. FAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. FAS 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, however earlier application is permitted provided the reporting entity has not yet issued financial statements for that fiscal year. We do not expect this guidance to have a significant impact on CNX Gas.
      In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. FAS 158 was issued to address concerns that prior standards on employers’ accounting for defined benefit postretirement plans failed to communicate the funded status of those plans in a complete and understandable way and to require an employer to recognize completely in earnings or other comprehensive income the financial impact of certain events affecting the plan’s funded status when those events occurred. This Statement is effective for financial statements issued for fiscal years ending after December 15, 2006. Retrospective application of this Statement is not permitted. We do not expect this guidance to have a significant impact on CNX Gas.
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 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.

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Operations
     We produced 14.4 Bcf in the quarter ended September 30, 2006, and 41.7 Bcf for the nine months ended September 30, 2006.
     During the quarter ended September 30, 2006, CNX Gas began production from 58 new CBM wells in Virginia operations (currently part of Central Appalachia and Tennessee) giving us a total of 186 new wells for the nine months ended September 30, 2006. Five additional wells were placed into production in Mountaineer (currently part of Northern Appalachia) since the one new well that was put into production in the first quarter. In Tennessee, 2.81 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 September 2006 quarter was also higher than the September 2005 quarter as the September 2005 quarter was negatively affected by an issue at CONSOL Energy’s Buchanan Mine.
Outlook
     We maintain our forecast of total net production of 55.7 Bcf in 2006 (including equity affiliates).
     The Duke Jewell Ridge Lateral pipeline, which connects CNX Gas’ production field in southwestern Virginia to East Tennessee Natural Gas’(ETNG) interstate pipeline to the south, has been completed and is currently operating. The Jewell Ridge Lateral gives CNX Gas an alternative outlet for its production in southwestern Virginia. In addition to providing CNX Gas with transportation flexibility, the Jewell Ridge Lateral provides access to growing east coast markets. CNX Gas has entered into a 15-year transportation agreement with ETNG for the firm transportation of 197,500 Dekatherms (Dth) per day on the Jewell Ridge Lateral, having initially contracted for 210,000 Dth per day of capacity.
     Our 2006 capital expenditures are now projected to be $175,000 down from earlier estimates of $190,000. A reduction of $10,000 was due to a gas processing unit not being needed in Mountaineer this year.
     In 2006, the company expects to drill 250 wells in its Virginia Operations and 18 in Mountaineer.
     A portion of our gas production is associated with coal mining activities at CONSOL Energy’s Buchanan Mine. These mining activities require the removal of water from the mine and the ventilation of the mine. Several lawsuits and permit appeals have been filed that could affect the removal of water from the mine. Separately, a lawsuit has been filed with respect to a ventilation fan that could affect the ventilation of the mine. If operations at CONSOL Energy’s Buchanan Mine are adversely affected as a result of these legal proceedings, our gas production relating to mining activities would be adversely affected.
     On October 11, 2006, the company adopted a Long-Term Incentive Program under the company’s Equity Incentive Plan, as amended. The purpose of the Program is to provide long-term incentive compensation to key employees of the Company and its affiliates in order to further align their interests with those of the Company’s shareholders. Each participant is awarded a target number of performance share units (including dividend rights). The units represent a contingent right to receive a cash payment, determined by reference to the value of one share of the Company’s common stock, to the extent such unit is earned and becomes payable pursuant to the terms of the Program. The total number of units earned by a participant, which may be from 0% to 250% of the target award, will be based on the company’s total shareholder return relative to the total shareholder return of each company in a group of 28 peer companies for the performance period from October 11, 2006 to December 31, 2009. As of October 11, 2006, the total cost of the plan is estimated to be approximately $7,700, which will be charged to compensation expense over the performance period. The actual cost of the plan will be determined as of the end of each quarter during the performance period using a probabilistic model and compensation expense will be appropriately adjusted.

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Results of Operations
Three Months Ended September 30, 2006 compared with Three Months Ended September 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
  $ 92,507     $ 71,681     $ 20,826       29.1 %
Related Party Sales
    2,719       1,926       793       41.2 %
Royalty Interest Gas Sales
    13,221       12,317       904       7.3 %
Purchased Gas Sales
    9,076       88,288       (79,212 )     (89.7 )%
Other Income
    6,044       2,100       3,944       187.8 %
 
                         
Total Revenue and Other Income
    123,567       176,312       (52,745 )     (29.9 )%
Costs and Expenses:
                               
Lifting Costs
    7,295       6,907       388       5.6 %
Gathering and Compression Costs
    13,949       10,696       3,253       30.4 %
Royalty Interest Gas Costs
    10,808       10,042       766       7.6 %
Purchased Gas Costs
    9,340       89,653       (80,313 )     (89.6 )%
Other
    2,265       2,741       (476 )     (17.4 )%
Equity in (Earnings) Loss of Affiliates
    45       88       (43 )     (48.9 )%
General and Administrative
    8,522       4,699       3,823       81.4 %
Depreciation, Depletion and Amortization
    9,546       8,671       875       10.1 %
 
                         
Total Costs and Expenses
    61,770       133,497       (71,727 )     (53.7 )%
 
                         
Earnings Before Income Taxes
    61,797       42,815       18,982       44.3 %
Income Taxes
    24,204       16,745       7,459       44.5 %
 
                         
Net Income
  $ 37,593     $ 26,070     $ 11,523       44.2 %
 
                         
     Net income for 2006 was improved primarily due to additional production and increased average sales prices, while also managing costs. Both purchased gas revenues and purchased gas costs have decreased in the current period as a result of the adoption of a new accounting standard effective January 1, 2006.
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
  $ 92,507     $ 71,681     $ 20,826       29.1 %
Related Party Sales
    2,719       1,926       793       41.2 %
Royalty Interest Gas Sales
    13,221       12,317       904       7.3 %
Purchased Gas Sales
    9,076       88,288       (79,212 )     (89.7 )%
Other Income
    6,044       2,100       3,944       187.8 %
 
                         
Total Revenue and Other Income
  $ 123,567     $ 176,312     $ (52,745 )     (29.9 )%
 
                         
     The decrease in total revenue and other income was primarily due to the accounting change related to purchased gas sales. Outside, related party and royalty interest gas sales have increased due to additional production and a higher average sales price per thousand cubic feet in 2006 compared to 2005.

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                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    14.4       12.4       2.0       16.1 %
Average Sales Price (per Mcf)
  $ 6.62     $ 5.93     $ 0.69       11.6 %
     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 as 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 September 30, 2006, these physical and financial hedges represented approximately 4.7 Bcf of our gas sales volumes at an average price of $7.73 per Mcf, compared to approximately 9.9 Bcf at an average price of $4.62 per Mcf for the three months ended September 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       1.8       0.1       5.6 %
Average Sales Price (per Mcf)
  $ 6.85     $ 6.94     $ (0.09 )     (1.3 )%
     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 average sales price is relatively flat as a 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       9.8       (8.4 )     (85.7 )%
Average Sales Price (per Mcf)
  $ 6.45     $ 9.03     $ (2.58 )     (28.6 )%
     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 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 requires 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, interest income, third party gathering revenue and other miscellaneous income:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Insurance Settlements
  $ 2,121     $     $ 2,121       100.0 %
Royalty Income
    2,620       1,766       854       48.4 %
Interest Income
    1,071             1,071       100.0 %
Third Party Gathering Revenue
    391       294       97       33.0 %
Other Miscellaneous
    (159 )     40       (199 )     (497.5 )%
 
                         
Total Other Income
  $ 6,044     $ 2,100     $ 3,944       187.8 %
 
                         
     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.
     Royalty income received from third parties, which is calculated as a percentage of the third parties’ sales price, increased period to period due to a cash settlement as a result of a lessee audit and an increase in average gas market prices.

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     Interest income increased in 2006, as a result of CNX Gas retaining cash collections as a separate stand alone company in the current period. As of September 30, 2005, CNX Gas had just begun to retain its own cash, which was previously retained by CONSOL Energy, resulting in zero interest income in the period.
     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.
Costs and Expenses
     Overall, costs and expenses decreased in 2006 primarily due to the accounting change related to purchased gas costs. 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
  $ 7,295     $ 6,907     $ 388       5.6 %
Gathering and Compression Costs
    13,949       10,696       3,253       30.4 %
Royalty Interest Gas Costs
    10,808       10,042       766       7.6 %
Purchased Gas Costs
    9,340       89,653       (80,313 )     (89.6 )%
Other
    2,265       2,741       (476 )     (17.4 )%
Equity in (Earnings) Loss of Affiliates
    45       88       (43 )     (48.9 )%
General & Administrative
    8,522       4,699       3,823       81.4 %
Depreciation, Depletion & Amortization
    9,546       8,671       875       10.1 %
 
                         
Total Costs and Expenses
  $ 61,770     $ 133,497     $ (71,727 )     (53.7 )%
 
                         
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    14.4       12.4       2.0       16.1 %
Average Lifting Costs (per Mcf)
  $ 0.51     $ 0.56     $ (0.05 )     (8.9 )%
     Lifting costs per unit sold decreased $0.05 per mcf in the period to period comparison, due largely to increased volumes and reduced severance taxes.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    14.4       12.4       2.0       16.1 %
Average Gathering and Compression Costs (per Mcf)
  $ 0.97     $ 0.86     $ 0.11       12.8 %
     The increase in gathering and compression costs was attributable to an additional $0.06 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 $0.06 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 $0.07 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. Maintenance and various other related activities have decreased $0.08 per Mcf as a result of the compressor conversions and increased production period to period. The sales production used to calculate this unit cost does not include volumes from third parties flowing on our lines.

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\

                                 
                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    1.9       1.8       0.1       5.6 %
Average Cost (per Mcf)
  $ 5.60     $ 5.66     $ (0.06 )     (1.1 )%
     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. The decrease in average cost per unit is the result of a slight decline in average sales price in the current period compared to the prior period. 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       9.8       (8.4 )     (85.7 )%
Average Purchased Gas Costs (per Mcf)
  $ 6.64     $ 9.17     $ (2.53 )     (27.6 )%
     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 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 requires 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
  $ 366     $ 472     $ (106 )     (22.5 )%
Gob Gas Collection Costs
    697       821       (124 )     (15.1 )%
Miscellaneous
    444       268       176       65.7 %
Land Related
    469       562       (93 )     (16.5 )%
Imbalance
    289       618       (329 )     (53.2 )%
 
                         
Total Other Costs and Expenses
  $ 2,265     $ 2,741     $ (476 )     (17.4 )%
 
                         
     Well site general maintenance costs decreased in 2006 due to various transactions, none of which were individually material.
     Gob gas collection costs decreased in 2006 due to the idling of a CONSOL Energy mine, which reduced the amount of gob collection required.
     Miscellaneous costs and expenses increased primarily due to various transactions that occurred in both periods, none of which were individually material.
     Land related costs have decreased slightly in 2006 due to the increased successful efforts of land acquisitions. Broker charges for successful acquisitions are capitalized where unsuccessful efforts are expended.
     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.
     Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 as follows:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Knox Energy
  $ 30     $ 76     $ (46 )     (60.5 )%
Coalfield Pipeline
    (40 )     (16 )     (24 )     (150.0 )%
Buchanan Generation
    55       28       27       96.4 %
 
                         
Total Equity in (Earnings) Loss of Affiliates
  $ 45     $ 88     $ (43 )     (48.9 )%
 
                         
     Knox Energy had a lower loss in 2006 compared to 2005 primarily due to higher realized prices and additional service revenue.

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     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 $8,522 in 2006 from $4,699 in 2005 primarily due to the additional costs related to becoming 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
  $ 6,357     $ 5,793     $ 564       9.7 %
Gathering
    3,189       2,878       311       10.8 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 9,546     $ 8,671     $ 875       10.1 %
 
                         
     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
  $ 61,797     $ 42,815     $ 18,982       44.3 %
Tax Expense
  $ 24,204     $ 16,745     $ 7,459       44.5 %
Effective Income Tax Rate
    39.2 %     39.1 %     0.1 %        
     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
Nine Months Ended September 30, 2006 compared with Nine Months Ended September 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
  $ 286,494     $ 192,878     $ 93,616       48.5 %
Related Party Sales
    5,753       5,325       428       8.0 %
Royalty Interest Gas Sales
    41,714       31,059       10,655       34.3 %
Purchased Gas Sales
    41,206       157,545       (116,339 )     (73.8 )%
Other Income
    19,475       6,627       12,848       193.9 %
 
                       
Total Revenue and Other Income
    394,642       393,434       1,208       0.3 %
Costs and Expenses:
                               
Lifting Costs
    21,990       19,087       2,903       15.2 %
Gathering and Compression Costs
    40,940       29,918       11,022       36.8 %
Royalty Interest Gas Costs
    34,491       24,505       9,986       40.8 %
Purchased Gas Costs
    42,091       159,739       (117,648 )     (73.7 )%
Other
    6,138       8,335       (2,197 )     (26.4 )%
Equity in (Earnings) Loss of Affiliates
    (727 )     220       (947 )     (430.5 )%
General and Administrative
    23,228       12,171       11,057       90.8 %
Depreciation, Depletion and Amortization
    27,437       25,883       1,554       6.0 %
 
                       
Total Costs and Expenses
    195,588       279,858       (84,270 )     (30.1 )%
 
                       
Earnings Before Income Taxes
    199,054       113,576       85,478       75.3 %
Income Taxes
    77,432       43,988       33,444       76.0 %
 
                       
Net Income
  $ 121,622     $ 69,588     $ 52,034       74.8 %
 
                       
     Net income for 2006 was improved primarily due to additional production and increased average sales prices, while also managing costs. Both purchased gas revenues and purchased gas costs have decreased in the current period as a result of the adoption of a new accounting standard effective January 1, 2006. The overall increase in total revenues was 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
  $ 286,494     $ 192,878     $ 93,616       48.5 %
Related Party Sales
    5,753       5,325       428       8.0 %
Royalty Interest Gas Sales
    41,714       31,059       10,655       34.3 %
Purchased Gas Sales
    41,206       157,545       (116,339 )     (73.8 )%
Other Income
    19,475       6,627       12,848       193.9 %
 
                         
Total Revenue and Other Income
  $ 394,642     $ 393,434     $ 1,208       0.3 %
 
                         
     The increase in total revenue and other income was primarily due to additional production and a higher average sales price per thousand cubic feet in 2006 compared to 2005. Purchased gas sales decreased due to the impact of the accounting change.

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                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    41.7       35.9       5.8       16.2 %
Average Sales Price (per Mcf)
  $ 7.01     $ 5.53     $ 1.48       26.8 %
     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 nine months ended September 30, 2006, these physical and financial hedges represented approximately 13.0 Bcf of our gas sales volumes at an average price of $7.49 per Mcf, compared to approximately 29.2 Bcf at an average price of $4.83 per Mcf for the nine months ended September 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)
    5.6       5.1       0.5       9.8 %
Average Sales Price (per Mcf)
  $ 7.42     $ 6.06     $ 1.36       22.4 %
     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)
    5.4       20.0       (14.6 )     (73.0 )%
Average Sales Price (per Mcf)
  $ 7.67     $ 7.87     $ (0.20 )     (2.5 )%
     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 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 requires 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
  $ 9,081     $     $ 9,081       100.0 %
Royalty Income
    7,198       5,667       1,531       27.0 %
Interest Income
    2,169             2,169       100.0 %
Third Party Gathering Revenue
    1,057       794       263       33.1 %
Other Miscellaneous
    (30 )     166       (196 )     (118.1 )%
 
                         
Total Other Income
  $ 19,475     $ 6,627     $ 12,848       193.9 %
 
                         
     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.
     Royalty income received from third parties is calculated as a percentage of the third parties’ sales price. Royalty income increased in 2006 compared to 2005 as average gas market prices increased period to period.

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     Interest income increased in 2006, as a result of CNX Gas retaining cash collections as a separate stand alone company in the current period. As of September 30, 2005, CNX Gas had just begun to retain its own cash, which was previously retained by CONSOL Energy, resulting in zero interest income in the period.
     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 the accounting change related to purchased gas costs. 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
  $ 21,990     $ 19,087     $ 2,903       15.2 %
Gathering and Compression Costs
    40,940       29,918       11,022       36.8 %
Royalty Interest Gas Costs
    34,491       24,505       9,986       40.8 %
Purchased Gas Costs
    42,091       159,739       (117,648 )     (73.7 )%
Other
    6,138       8,335       (2,197 )     (26.4 )%
Equity in (Earnings) Loss of Affiliates
    (727 )     220       (947 )     (430.5 )%
General & Administrative
    23,228       12,171       11,057       90.8 %
Depreciation, Depletion & Amortization
    27,437       25,883       1,554       6.0 %
 
                         
Total Costs and Expenses
  $ 195,588     $ 279,858     $ (84,270 )     (30.1 )%
 
                         
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    41.7       35.9       5.8       16.2 %
Average Lifting Costs (per Mcf)
  $ 0.53     $ 0.53     $ 0.00       0.0 %
     Lifting costs per Mcf are unchanged in the period to period comparison. Higher realized sales prices increased production taxes $0.04 per Mcf period to period, however this increase was offset by decreases in various miscellaneous items due to the increase in production.
                                 
                            Percentage
    2006   2005   Variance   Change
Sales Volumes (Bcf)
    41.7       35.9       5.8       16.2 %
Average Gathering and Compression Costs (per Mcf)
  $ 0.98     $ 0.83     $ 0.15       18.1 %
     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 $0.07 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. The sales production used to calculate this unit cost does not include volumes from third parties flowing on our lines.

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                            Percentage
    2006   2005   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    5.6       5.1       0.5       9.8 %
Average Cost (per Mcf)
  $ 6.13     $ 4.78     $ 1.35       28.2 %
     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. The increase in average cost per unit is the result of an increase in average sales price in the current period compared to the prior period. 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)
    5.4       20.0       (14.6 )     (73.0 )%
Average Purchased Gas Costs (per Mcf)
  $ 7.84     $ 7.98     $ (0.14 )     (1.8 )%
     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 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 requires 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 nine 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
  $ 2,166     $ 2,022     $ 144       7.1 %
Gob Gas Collection Costs
    2,081       2,237       (156 )     (7.0 )%
Land Related
    1,055       1,027       28       2.7 %
Miscellaneous
    1,418       260       1,158       445.4 %
Imbalance
    (582 )     1,462       (2,044 )     (139.8 )%
Accounts Receivable Securitization Fees
          1,327       (1,327 )     (100.0 )%
 
                         
Total Other Costs and Expenses
  $ 6,138     $ 8,335     $ (2,197 )     (26.4 )%
 
                         
     Well site general maintenance costs increased in 2006 due to various transactions, none of which were individually material.
     Gob gas collection costs decreased in 2006 due to the idling of a CONSOL Energy mine, which reduced the amount of gob collection required.
     Even though our success rate for land acquisitions has increased, land related costs have in total 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.
     Miscellaneous costs and expenses increased primarily due to various transactions that occurred in both periods, none of which were individually material.
     The value of the gas imbalance has shifted from the prior year as the 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.
     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.

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     Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 as follows:
                                 
                    Dollar     Percentage  
    2006     2005     Variance     Change  
Knox Energy
  $ (1,136 )   $ 84     $ (1,220 )     (1,452.4 )%
Coalfield Pipeline
    (44 )     (35 )     (9 )     (25.7 )%
Buchanan Generation
    453       171       282       164.9 %
 
                         
Total Equity in (Earnings) Loss of Affiliates
  $ (727 )   $ 220     $ (947 )     (430.5 )%
 
                         
     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 higher earnings in 2006 compared to 2005 primarily due to additional third party gathering revenue.
     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 $23,228 in 2006 from $12,171 in 2005 primarily due to the additional costs related to becoming 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
  $ 18,002     $ 17,251     $ 751       4.4 %
Gathering
    9,435       8,632       803       9.3 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 27,437     $ 25,883     $ 1,554       6.0 %
 
                         
     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
  $ 199,054     $ 113,576     $ 85,478       75.3 %
Tax Expense
  $ 77,432     $ 43,988     $ 33,444       76.0 %
Effective Income Tax Rate
    38.9 %     38.7 %     0.2 %        
     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. No amounts are outstanding under our credit facility at September 30, 2006.
     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 indenture and the agreement governing CONSOL Energy’s 8.25% medium term notes due in 2007 in the principal amount of $45,000 would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes.

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     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 asset of $520, net of $203 of deferred tax at September 30, 2006. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings in the nine months ended September 30, 2006.
Cash Flows (in thousands)
                         
    Year to Date   Year to Date         
    2006   2005   Change
Cash provided by operating activities
  $ 205,943     $ 124,896     $ 81,047  
Cash used in investing activities
  $ (118,440 )   $ (72,904 )   $ (45,536 )
Cash used in financing activities
  $     $ (22,439 )   $ 22,439  
     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.
     Cash used in financing activities in the prior period 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 September 30, 2006. We estimate payments, net of any applicable reimbursements, related to these items at September 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 (a)
    66,919       2,343       5,643       6,535       52,398  
Operating Lease Obligations
    5,280       820       1,650       1,661       1,149  
Other Long-Term Liabilities:
                                       
Gas Firm Transportation Obligation
    19,606       3,758       7,692       5,512       2,644  
Other Liabilities (b)
    13,659                         13,659  
Well Plugging Liabilities
    8,723       378       756       756       6,833  
Pension
    398       1       8       35       354  
Postemployment Benefits Other than Pension
    3,337       5       44       104       3,184  
 
                             
Total Contractual Obligations
  $ 117,922     $ 7,305     $ 15,793     $ 14,603     $ 80,221  
 
                             
 
(a)   In conjunction with the completion of the Jewell Ridge lateral pipeline in October 2006, CNX Gas entered into a 15 year firm transportation agreement with ETNG, a subsidiary of Duke Energy, at pre-determined fixed rates. The present value of our payments under this firm transportation agreement is approximately $67 million. In addition to providing us with transportation flexibility, the Jewell Ridge lateral will provide access for our production to alternate and growing Southeastern and East Coast markets.
(b)   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;

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    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. 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 nine months ended September 30, 2006 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of September 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)
  $ 14.4     $ 34.4  
 
(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 September 30, 2006, the fair value of these contracts was a net asset of $520, net of $203 deferred tax. We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

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Hedging Volumes
As of September 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.
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 September 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.
     During the quarter, CNX Gas began the implementation a new accounting software system, which provides expanded functionality specifically applicable to our gas exploration and production business. This project has resulted in certain changes to internal controls over financial reporting and further changes are anticipated as the implementation continues. Management is taking appropriate steps to monitor and maintain internal controls during this period of change. Except for the foregoing, 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.
PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
     The second through fifth 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.

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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
     None
ITEM 5. OTHER INFORMATION
     None
ITEM 6. EXHIBITS
     
10.1
  CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.1.*
 
   
10.2
  Form of Award Agreement under the CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.2.*
 
   
10.3
  First Amendment to the CNX Gas Corporation Equity Incentive Plan, as amended, is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.3*
 
   
10.4
  Summary of Non-Employee Director Compensation effective as of November 1, 2006 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.4.*
 
   
10.5
  Summary of the awards to the company’s executive officers under the CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared under the caption “Unit Awards under the Program.”*
 
   
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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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: November 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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Table of Contents

         
EXHIBIT INDEX
     
10.1
  CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.1.*
 
   
10.2
  Form of Award Agreement under the CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.2.*
 
   
10.3
  First Amendment to the CNX Gas Corporation Equity Incentive Plan, as amended, is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.3*
 
   
10.4
  Summary of Non-Employee Director Compensation effective as of November 1, 2006 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared as exhibit 10.4.*
 
   
10.5
  Summary of the awards to the company’s executive officers under the CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 is incorporated by reference from the company’s Current Report on Form 8-K filed on October 17, 2006, wherein it appeared under the caption “Unit Awards under the Program.”*
 
   
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.

33

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