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CNX Gas 10-Q 2007
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, 2007
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     
Commission file number: 001-32723
 
CNX GAS CORPORATION
(Exact name of registrant as specified in its charter)
 
     
Delaware   20-3170639
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
5 Penn Center West, Suite 401
Pittsburgh, PA 15276-0102
(412) 200-6700


 
(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 Exchange Act). Yes o      No þ
The number of shares of the registrant’s common stock outstanding as of September 30, 2007 is 150,910,198 shares.
 
 

 


 

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

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

(Dollars in thousands, except per share data)
                                 
    For the Three Months Ended     For the Nine Months Ended  
    September 30,     September 30,  
    2007     2006     2007     2006  
Revenue and Other Income:
                               
Outside Sales
  $ 96,222     $ 92,507     $ 306,615     $ 286,494  
Related Party Sales
    2,379       2,719       6,980       5,753  
Royalty Interest Gas Sales
    10,175       13,221       36,841       41,714  
Purchased Gas Sales
    821       9,076       3,297       41,206  
Other Income
    208       6,044       4,675       19,475  
 
                       
Total Revenue and Other Income
    109,805       123,567       358,408       394,642  
 
                       
Costs and Expenses:
                               
Lifting Costs
    8,588       7,775       25,617       24,115  
Gathering and Compression Costs
    15,283       14,646       46,593       43,021  
Royalty Interest Gas Costs
    8,543       10,808       31,736       34,491  
Purchased Gas Costs
    495       9,340       2,987       42,091  
Other
    (1,363 )     1,021       228       783  
General and Administrative
    12,793       8,634       39,069       23,641  
Depreciation, Depletion and Amortization
    12,248       9,546       36,325       27,437  
Interest Expense
    1,221             3,686       9  
 
                       
Total Costs and Expenses
    57,808       61,770       186,241       195,588  
 
                       
Earnings Before Income Taxes
    51,997       61,797       172,167       199,054  
Income Taxes
    20,701       24,204       66,387       77,432  
 
                       
Net Income
  $ 31,296     $ 37,593     $ 105,780     $ 121,622  
 
                       
Earnings Per Share:
                               
Basic
  $ 0.21     $ 0.25     $ 0.70     $ 0.81  
 
                       
Diluted
  $ 0.21     $ 0.25     $ 0.70     $ 0.81  
 
                       
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,895,233       150,850,930       150,877,067       150,839,264  
 
                       
Dilutive
    151,149,432       151,029,192       151,103,827       150,998,713  
 
                       
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,  
    2007     2006  
ASSETS
               
Current Assets:
               
Cash and Cash Equivalents
  $ 58,403     $ 107,173  
Accounts Receivable:
               
Trade
    31,143       46,062  
Net Related Party
          2,745  
Other
    1,452       2,291  
Derivatives
    13,723       10,548  
Other Current Assets
    2,564       3,917  
 
           
Total Current Assets
    107,285       172,736  
Property, Plant and Equipment, Net
    1,147,278       918,162  
Other Assets
    9,689       11,820  
Investments in Equity Affiliates
    55,872       52,283  
 
           
TOTAL ASSETS
  $ 1,320,124     $ 1,155,001  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities:
               
Accounts Payable:
               
Trade
  $ 16,794     $ 27,872  
Net Related Party
    152        
Accrued Royalties Payable
    10,620       11,960  
Accrued Severance Taxes
    2,337       2,576  
Accrued Income Taxes
    1,385       2,191  
Deferred Taxes
    2,432       3,091  
Other Current Liabilities
    13,357       9,222  
 
           
Total Current Liabilities
    47,077       56,912  
Long-Term Debt:
               
Long-Term Debt (Note 6)
    6,240        
 
           
Total Long-Term Debt
    6,240        
Deferred Credits and Other Liabilities:
               
Deferred Taxes
    173,222       120,008  
Capital Lease Obligation
    61,838       63,897  
Other Liabilities
    30,555       15,977  
Well Plugging Liabilities
    3,402       9,214  
Derivatives
    269       6,465  
Postretirement Benefits Other Than Pension
    2,436       2,313  
 
           
Total Deferred Credits and Other Liabilities
    271,722       217,874  
 
           
Total Liabilities
    325,039       274,786  
 
           
Stockholders’ Equity
               
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,910,198 Issued and Outstanding at September 30, 2007 and 150,864,075 Issued and Outstanding at December 31, 2006
    1,509       1,508  
Capital in Excess of Par Value
    784,632       781,960  
Retained Earnings
    200,064       94,337  
Accumulated Other Comprehensive Income
    8,880       2,410  
 
           
Total Stockholders’ Equity
    995,085       880,215  
 
           
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 1,320,124     $ 1,155,001  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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

(Dollars in thousands)
                                         
                            Accumulated        
            Capital in             Other     Total  
    Common     Excess of     Retained     Comprehensive     Stockholders’  
    Stock     Par Value     Earnings     Income (Loss)     Equity  
Balance at December 31, 2006
  $ 1,508     $ 781,960     $ 94,337     $ 2,410     $ 880,215  
Net Income
                105,780             105,780  
Gas Cash Flow Hedge (Net of $3,640 tax)
                      6,549       6,549  
 
                             
Comprehensive Income (Loss) (a)
                105,780       6,549       112,329  
FASB Interpretation No. 48 Adoption
                (53 )           (53 )
Stock Options Exercised
    1       220                   221  
Tax Benefit from Stock Based Compensation
          35                   35  
Amortization of Restricted Stock Unit Grants
          478                   478  
Amortization of Stock Option Grants
          1,939                   1,939  
Actuarial Salary OPEB revaluation (net of $44 tax)
                      (69 )     (69 )
Actuarial Pension revaluation (net of $7 tax)
                      (10 )     (10 )
 
                             
Balance at September 30, 2007
  $ 1,509     $ 784,632     $ 200,064     $ 8,880     $ 995,085  
 
                             
 
(a)   Of the $6,549 net change in accumulated other comprehensive income (loss) in the period, $12,428 represents hedging gains recognized in net income for the portions of the financial hedges that settled in the current period.
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,  
    2007     2006  
Operating Activities:
               
Net Income
  $ 105,780     $ 121,622  
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
               
Depreciation, Depletion and Amortization
    36,325       27,437  
Compensation from Restricted Stock Unit Grants
    478       654  
Compensation from Stock Option Grants
    1,939       1,423  
Deferred Income Taxes
    52,121       45,345  
Equity in Earnings of Affiliates
    (1,330 )     (727 )
Changes in Operating Assets:
               
Accounts Receivable
    15,758       7,308  
Related Party Receivable
    2,745       57  
Other Current Assets
    1,353       (161 )
Changes in Other Assets
    2,131       845  
Changes in Operating Liabilities:
               
Accounts Payable
    (7,190 )     (3,855 )
Related Party Payable
    152        
Income Taxes
    (771 )     1,073  
Other Current Liabilities
    (332 )     758  
Changes in Other Liabilities
    3,170       3,690  
Other
    (1,254 )     474  
 
           
Net Cash Provided by Operating Activities
    211,075       205,943  
 
           
Investing Activities:
               
Capital Expenditures
    (194,967 )     (117,037 )
Acquisition of Mineral Rights
    (61,149 )      
Capital Expenditures of Variable Interest Entity
    (9,000 )      
Investment in Equity Affiliates
    (2,259 )     (1,403 )
Proceeds From Sales of Assets
    187        
 
           
Net Cash (Used in) Investing Activities
    (267,188 )     (118,440 )
 
           
Financing Activities:
               
Capital Lease Payments
    (1,912 )      
Proceeds from the Debt of Variable Interest Entity
    9,000        
Exercise of Stock Options
    220        
Tax Benefit from Stock Based Compensation
    35        
 
           
Net Cash Provided by Financing Activities
    7,343        
 
           
Net (Decrease) Increase in Cash and Cash Equivalents
    (48,770 )     87,503  
Cash and Cash Equivalents at Beginning of Period
    107,173       20,073  
 
           
Cash and Cash Equivalents at End of Period
  $ 58,403     $ 107,576  
 
           
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, except per share data)
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 statement have been reflected in the interim periods presentation. Operating results for the three and nine month periods ended September 30, 2007 are not necessarily indicative of the results that may be expected for future periods.
     Certain reclassifications of previously reported data have been made to conform to the three and nine months ended September 30, 2007 classifications. Unless otherwise noted, we discuss dollars in thousands throughout this Form 10-Q. Unless otherwise noted, we discuss production, per unit revenues, and per unit costs net of any royalty owners’ interest. Unless noted otherwise, production figures are exclusive of production attributable to equity affiliates.
     The consolidated financial statements of CNX Gas include the accounts of majority-owned and controlled subsidiaries. As defined by FASB Interpretation (FIN) No. 46, “Consolidation of Variable Interest Entities-an Interpretation of ARB No. 51,” and related interpretations, the accounts of variable interest entities (VIEs) where CNX Gas is the primary beneficiary are included in the consolidated financial statements. We are the primary beneficiary of one variable interest entity, a third party drilling contractor, where CNX Gas guarantees certain debt and is the primary customer of that entity. For further information regarding this VIE, see our disclosures within Note 6 - Commitments and Contingent Liabilities. Investments in business entities in which CNX Gas does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation.
     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 is 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. 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.
     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 the effect of dilutive potential common shares outstanding during the period as calculated in accordance with Statement of Financial Accounting Standards No. 123(R), “Accounting for Stock-Based Compensation” (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. Options to purchase 491,056 and 471,806 shares of common stock outstanding for the three month periods ending September 30, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because the effect would be anti-dilutive. Options to purchase 493,815 and 471,806 shares of common stock outstanding for the nine month periods ending September 30, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because the effect would be anti-dilutive.

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     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,  
    2007     2006     2007     2006  
Net Income
  $ 31,296     $ 37,593     $ 105,780     $ 121,622  
 
                       
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    150,895,233       150,850,930       150,877,067       150,839,264  
Effect of stock based compensation
    254,199       178,262       226,760       159,449  
 
                       
Dilutive
    151,149,432       151,029,192       151,103,827       150,998,713  
 
                       
Earnings per share:
                               
Basic
  $ 0.21     $ 0.25     $ 0.70     $ 0.81  
 
                       
Diluted
  $ 0.21     $ 0.25     $ 0.70     $ 0.81  
 
                       
Note 2—Acquisitions:
     In April 2007, CNX Gas acquired by lease 20,000 acres in southwestern Pennsylvania from a subsidiary of Massey Energy Company. The acreage has no proved gas reserves and is in close proximity to our Mountaineer and Nittany plays. Under the agreement, CNX Gas and the Massey subsidiary will jointly develop the property, with CNX Gas serving as the operator and majority interest partner.
     In May 2007, CNX Gas acquired by lease approximately 70,000 acres of oil and gas reserves in Western Kentucky from a subsidiary of Atmos Energy Corporation and Teal Royalties LLC. The acreage has no proved gas reserves and is in close proximity to our existing acreage in the New Albany Shale.
     In June 2007, CNX Gas entered into a three-way transaction with Peabody Energy and majority shareholder CONSOL Energy Inc. (CONSOL or CONSOL Energy) to acquire certain oil and gas, coalbed methane, and other gas interests. Pursuant to the transaction, CNX Gas acquired certain coal assets from CONSOL for $45,000 cash, plus $1,149 of miscellaneous acquisition costs, plus a future payment with an estimated present value of $6,500, which we approximate to be the fair value of the assets. CNX Gas then exchanged those assets plus $15,000 cash for Peabody’s oil and gas, coalbed methane, and other gas rights to approximately 1,037,000 acres, including 655,000 in the Illinois Basin, 151,000 acres in Northern Appalachia, 171,000 acres in the San Juan Basin, 47,000 acres in the Powder River Basin, and 11,000 acres in the Rockies. This acreage has no proved gas reserves.
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  
    2007     2006     2007     2006     2007     2006     2007     2006  
Components of Net Periodic Benefit Costs:
                                                               
Service costs
  $ 65     $ 70     $ 31     $ 23     $ 195     $ 210     $ 93     $ 69  
Interest costs
    3       1       35       25       9       3       105       75  
Expected return on assets
          (2 )                 1       (6 )            
Amortization of prior service costs credit
                (43 )     (43 )                 (129 )     (129 )
Amortization of (gain) loss
    (6 )     (3 )     5             (18 )     (9 )     15        
 
                                               
Benefit costs
  $ 62     $ 66     $ 28     $ 5     $ 187     $ 198     $ 84     $ 15  
 
                                               
     As previously disclosed in the notes to its audited consolidated financial statements for the year ended December 31, 2006, CNX Gas does not expect to contribute to the other postretirement benefit plan in 2007. We intend to pay benefit claims as they become due. For the three and nine month periods ended September 30, 2007, there were $28 and $79 in payments made pursuant to the other postretirement benefit plan. For the three and nine month periods ended September 30, 2007, there were $237 and $284 in contributions made pursuant to the pension plan.

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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,  
    2007     2006  
    Dollars     Rate     Dollars     Rate  
Statutory U.S. Federal Income Tax
  $ 60,258       35.0 %   $ 69,669       35.0 %
Net Effect of State Income Tax
    7,145       4.1 %     8,619       4.3 %
Other
    (1,016 )     (0.5 )%     (856 )     (0.4 )%
 
                       
Income Tax Expense/Effective Rate
  $ 66,387       38.6 %   $ 77,432       38.9 %
 
                       
     The effective tax rate for the nine months ended September 30, 2007 and 2006 was calculated using the annual effective rate projection on recurring earnings. CNX Gas is included in the consolidated federal tax return of CONSOL Energy. Income taxes are calculated as if CNX Gas files a tax return on a separate company basis. With few exceptions, CNX Gas is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2002. The Internal Revenue Service (IRS) commenced an examination of CONSOL Energy’s U.S. income tax returns for 2004 and 2005 in 2006. This examination is anticipated to be completed by the end of 2008. As of September 30, 2007, the IRS has not proposed any significant adjustments relating to any tax position taken by CNX Gas as part of CONSOL Energy’s consolidated return.
     CNX Gas adopted the provisions of FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes”, on January 1, 2007. As a result of the implementation of FIN No. 48, CNX Gas recognized approximately a $53 net increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. As of September 30, 2007, CNX Gas does not anticipate a significant change in our uncertain tax positions.
     Included in the balance at September 30, 2007 are $3,116 of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate, but would accelerate the payment of cash to the taxing authority to an earlier period.
     CNX Gas recognizes interest accrued related to unrecognized tax benefits in its interest expense. For the nine month period ended September 30, 2007, CNX Gas recognized interest expense of approximately $57. Total FIN No. 48 accrued interest was $150 as of September 30, 2007.
     CNX Gas recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. No penalties have been accrued during the quarter ended September 30, 2007. CNX Gas has historically not paid penalties relating to unrecognized tax benefits.
Note 5—Property, Plant and Equipment:
                 
    September 30,     December 31,  
    2007     2006  
Leasehold Improvements
  $ 783     $  
Surface Lands
    61,688       37,055  
Mineral Interests
    125,040       55,623  
Wells and Related Equipment
    146,305       112,009  
Intangible Drilling
    472,390       383,605  
Gathering Assets
    571,795       520,906  
Gas Well Plugging
    371       5,652  
Capitalized Internal Software
    6,536       6,433  
 
           
Total Property, Plant and Equipment
    1,384,908       1,121,283  
Accumulated Depreciation, Depletion and Amortization
    (237,630 )     (203,121 )
 
           
Property, Plant and Equipment, Net
  $ 1,147,278     $ 918,162  
 
           

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Note 6—Commitments and Contingent Liabilities:
     CNX Gas Company LLC is a party to a case captioned GeoMet Operating Company, Inc. and Pocahontas Mining Limited Liability Company v. CNX Gas Company LLC in the Circuit Court for Buchanan County, Virginia (Case No. 337-06). CNX Gas has a coal seam gas lease with Pocahontas Mining in southwest Virginia and southern West Virginia. With the agreement of Pocahontas Mining, GeoMet constructed a pipeline on the property. CNX Gas sought a judicial determination that under the terms of the lease, CNX Gas has the exclusive right to construct and operate pipelines on the property. On May 23, 2007, the circuit court entered an Order granting CNX Gas’ motion for summary judgment against GeoMet and Pocahontas Mining. The order provided that CNX Gas has exclusive rights to construct and operate pipelines on the property and prohibited GeoMet from owning, operating, or maintaining its pipeline on the property. The court stayed the portion of its order that required GeoMet to remove its pipeline, pending GeoMet’s appeal of the decision to the Virginia Supreme Court. GeoMet filed an emergency appeal to the Virginia Supreme Court, which on June 20, 2007, overturned the provision of the circuit court’s order requiring GeoMet to remove its pipeline, as well as the related stay and the conditions thereof. The remaining portions of the May 23, 2007 order have been certified for interlocutory appeal to the Virginia Supreme Court. Pocahontas Mining has amended its complaint to seek rescission or reformation of the lease. CNX Gas believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
     On February 14, 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CNX Gas Company LLC and Island Creek Coal Company, a subsidiary of CONSOL Energy, in the Circuit Court for the County of Tazewell, Virginia (Case No. CL07000065-00). The lawsuit alleges that CNX Gas conspired with Island Creek and has violated the Virginia Antitrust Act and tortiously interfered with GeoMet’s contractual relations, prospective contracts and business expectancies. GeoMet seeks injunctive relief, actual damages of $561,000, treble damages and punitive damages in the amount of $350. CNX Gas and Island Creek have filed motions to dismiss all counts of the complaint. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
     In April, 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 CNX Gas Company LLC in the Circuit Court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002; the county has since filed and served two substantially similar cases for years 2003, 2004 and 2005. The complaint alleges that our calculation of the license tax on the basis of the wellhead price (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, we paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, 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. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
     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. A number of our wells, particularly in Northern Appalachia, could be covered by their claim. We deny all of these allegations and we are vigorously contesting 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 claim of any valid and enforceable CDX patent. CDX filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain claims 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 claims of the patents in suit, if those patents are ultimately determined to be valid and enforceable. The report of CDX’s damages expert suggests that CDX will seek (i) reasonable royalty damages on production from allegedly infringing wells at a royalty rate of 10%, or approximately $1,900 based on projected production through June 2007, and (ii) “lost profits” damages of approximately $23,600 for allegedly infringing wells drilled though August 2006, which assumes that CNX Gas would have no choice but to have entered into a joint operating arrangement with CDX. We believe that there is no valid basis in the law as applied to the facts of this case for this “lost profits” theory. Further, if infringement were to be found of a valid, enforceable claim of a CDX patent, the report of CNX Gas’ damages expert indicates that any potential damages award would be based on a royalty of 5%, or approximately $400. Cross-motion for summary judgment as to infringement, invalidity and

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unenforceability have been filed and briefed by CNX Gas and CDX and are before a Special Master for decision in the form of a report and recommendation to the District Court. We continue to believe that we do not infringe any properly construed claim of any valid, enforceable patent. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
     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. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
     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 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.
     At September 30, 2007, CNX Gas has provided the following financial guarantees and letters of credit to certain third parties. CNX Gas believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.
                                         
    Total                              
    Amounts     Less Than                     Beyond  
    Committed     1 Year     1-3 Years     3-5 Years     5 years  
Letters of Credit:
                                       
Gas
  $ 14,933     $ 14,913     $ 20     $     $  
 
                             
Total Letters of Credit
  $ 14,933     $ 14,913     $ 20     $     $  
Surety Bonds:
                                       
Environmental
  $ 481     $ 481     $     $     $  
Other
    21,827       21,827                    
 
                             
Total Surety Bonds
  $ 22,308     $ 22,308     $     $     $  
Other:
                                       
Firm Transportation
  $ 50,655     $ 7,392     $ 14,554     $ 10,482     $ 18,227  
Guarantees
    11,191       11,191                    
 
                             
Total Guarantees
  $ 61,846     $ 18,583     $ 14,554     $ 10,482     $ 18,227  
 
                             
Total Commitments
  $ 99,087     $ 55,804     $ 14,574     $ 10,482     $ 18,227  
 
                             

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     As previously disclosed in the notes to our audited consolidated financial statements for the year ended December 31, 2006, 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.
     Letters of Credit
     On December 28, 2006, CNX Gas obtained the issuance of a letter of credit to the Commonwealth of Pennsylvania in the amount of $20 to serve as collateral for a one year period for a permit issued by PENNDOT.
     On May 2, 2007, CNX amended a letter of credit to East Tennessee Natural Gas, LLC which serves as collateral for a fifteen year firm transportation contract on the Jewell Ridge lateral, which had an in-service date of October 2006. The amount of the letter of credit at September 30, 2007 is $14,761.
     On April 15, 2005, CNX Gas obtained the issuance of a letter of credit to Allegheny Energy Supply Co. to serve as collateral for a period of two years to cover a potential tax liability of $152.
     Surety Bonds
     CNX Gas has issued surety bonds totaling $22,308. CNX Gas guarantees the performance of these obligations.
     Other Guarantees
     A guarantee agreement with Constellation Energy Commodities Group, Inc. for $1,000 is dated October 9, 2006.
     Variable Interest
     CNX Gas is a guarantor of the obligations for a CNX Gas contractor (debtor) under a loan agreement with Huntington National Bank (lender) dated November 27, 2006. This guarantee causes the debtor to be characterized as a variable interest entity for purposes of FASB Interpretation (FIN) No. 46, “Consolidation of Variable Interest Entities-an Interpretation of ARB No. 51”. This guarantee is related to the debtor’s procurement of two drilling rigs dedicated to serve CNX Gas and is capped at $10,000. We are the primary beneficiary of the variable interest as CNX Gas guarantees the debt and is the sole customer of that entity. FIN 46 requires us to consolidate their financial results into our financial statements as a variable interest entity at their fair value as of the date CNX Gas became the primary beneficiary, which was in April 2007.
     As of September 30, 2007, the outstanding balance on the loan agreement was $9,000, of which $2,760 is current and $6,240 is long term. Consequently, we have consolidated the drilling rigs in our property, plant and equipment and have recorded the related debt at its fair market value of $9,000. The impact on the income statement was immaterial. In July 2007, the full $9,000 was drawn on the loan.
     The guaranty continues until the indebtedness has been fully satisfied, but does not extend beyond the maturity date of December 31, 2010. The loan is collateralized by the drilling rigs. CNX Gas holds a secured position in the collateral second to the bank. Any failure of the CNX Gas contractor to satisfy this obligation would require CNX Gas to make payment in full to Huntington National Bank. Under a separate security agreement with the contractor, upon default CNX Gas may require re-payment by the contractor, sell the assets, or retain them for its own use.

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Note 7—Segment Information:
     The principal activity of CNX Gas is to produce methane gas for sale primarily to gas wholesalers. CNX Gas has two reportable segments: Central Appalachia and Other, and Northern Appalachia. During the fourth quarter 2006, management adjusted the manner in which results were internally reported to the chief operating decision maker. As a result of this change, the current period and all prior periods presented have been restated to reflect the way CNX Gas manages its operations and makes business decisions.
     Reportable segment results for the three months ended September 30, 2007 are:
                                                                 
    Central                                                  
    Appalachia     Northern     Total             Adjustments &                        
    and Other     Appalachia     Gas     Corporate     Eliminations     Consolidated                  
Sales—outside
  $ 87,603     $ 8,619     $ 96,222     $     $     $ 96,222                  
Sales—related parties
    2,369       10       2,379                   2,379                  
Sales—royalty interest
    10,165       10       10,175                   10,175                  
Sales—purchased gas
    821             821                   821                  
Other revenue
    (422 )           (422 )     630             208                  
Intersegment revenues
    19,026       711       19,737             (19,737 )                      
 
                                                   
Total Revenue and Other Income
  $ 119,562     $ 9,350     $ 128,912     $ 630     $ (19,737 )   $ 109,805                  
 
                                                   
Earnings Before Income Taxes
  $ 51,321     $ 5     $ 51,326     $ 671     $     $ 51,997       (A)          
 
                                                   
Segment assets
  $ 1,071,858     $ 165,086     $ 1,236,944     $ 83,180     $     $ 1,320,124       (B)(C)        
 
                                                   
Depreciation, depletion and amortization
  $ 10,636     $ 1,612     $ 12,248     $     $     $ 12,248                  
 
                                                   
Capital expenditures and Acquisition of Mineral Rights
  $ 36,819     $ 36,394     $ 73,213     $     $     $ 73,213                  
 
                                                   
 
(A)   Includes equity in earnings of unconsolidated affiliates of $650 and $277 for Central Appalachia and Corporate Segments, respectively.
 
(B)   Includes investments in unconsolidated equity affiliates of $31,095 and $24,777 for Central Appalachia and Corporate Segments, respectively.
 
(C)   Includes cash of $58,403 in the Corporate Segment.
     Reportable segment results for the three months ended September 30, 2006 are:
                                                                 
    Central                                                  
    Appalachia     Northern     Total             Adjustments &                        
    and Other     Appalachia     Gas     Corporate     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
    13,203       18       13,221                   13,221                  
Sales—purchased gas
    9,076             9,076                   9,076                  
Other revenue
    4,962       11       4,973       1,071             6,044                  
Intersegment revenues
    15,131       333       15,464             (15,464 )                      
 
                                                   
Total Revenue and Other Income
  $ 132,707     $ 5,253     $ 137,960     $ 1,071     $ (15,464 )   $ 123,567                  
 
                                                   
Earnings Before Income Taxes
  $ 60,713     $ 300     $ 61,013     $ 784     $     $ 61,797       (D)          
 
                                                   
Segment assets
  $ 844,073     $ 51,186     $ 895,259     $ 132,311     $     $ 1,027,570       (E)(F)          
 
                                                   
Depreciation, depletion and amortization
  $ 8,817     $ 729     $ 9,546     $     $     $ 9,546                  
 
                                                   
Capital expenditures
  $ 25,951     $ 8,077     $ 34,028     $     $     $ 34,028                  
 
                                                   
 
(D)   Includes equity in earnings (loss) of unconsolidated affiliates of $10 and ($55) for Central Appalachia and Corporate Segments, respectively.
 
(E)   Includes investments in unconsolidated equity affiliates of $26,923 and $24,735 for Central Appalachia and Corporate Segments, respectively.
 
(F)   Includes cash of $107,576 in the Corporate Segment.

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     Reportable segment results for the nine months ended September 30, 2007 are:
                                                                 
    Central                                                  
    Appalachia     Northern     Total             Adjustments &                        
    And Other     Appalachia     Gas     Corporate     Eliminations     Consolidated                  
Sales—outside
  $ 286,040     $ 20,575     $ 306,615     $     $     $ 306,615                  
Sales—related parties
    6,940       40       6,980                   6,980                  
Sales—royalty interest
    36,758       83       36,841                   36,841                  
Sales—purchased gas
    3,297             3,297                   3,297                  
Other revenue
    1,312             1,312       3,363             4,675                  
Intersegment revenues
    58,363       2,195       60,558             (60,558 )                      
 
                                                   
Total Revenue and Other Income
  $ 392,710     $ 22,893     $ 415,603     $ 3,363     $ (60,558 )   $ 358,408                  
 
                                                   
Earnings (Loss) Before Income Taxes
  $ 173,133     $ (3,631 )   $ 169,502     $ 2,665     $     $ 172,167       (G)          
 
                                                   
Segment assets
  $ 1,071,858     $ 165,086     $ 1,236,944     $ 83,180     $     $ 1,320,124       (H)(I)          
 
                                                   
Depreciation, depletion and amortization
  $ 31,809     $ 4,516     $ 36,325     $     $     $ 36,325                  
 
                                                   
Capital expenditures and Acquisition of Mineral Rights
  $ 171,311     $ 93,805     $ 265,116     $     $     $ 265,116                  
 
                                                   
 
(G)   Includes equity in earnings of unconsolidated affiliates of $1,313 and $17 for Central Appalachia and Corporate Segments, respectively.
 
(H)   Includes investments in unconsolidated equity affiliates of $31,095 and $24,777 for Central Appalachia and Corporate Segments, respectively.
 
(I)   Includes cash of $58,403 in the Corporate Segment.
     Reportable segment results for the nine months ended September 30, 2006 are:
                                                                 
    Central                                                  
    Appalachia     Northern     Total             Adjustments &                        
    And Other     Appalachia     Gas     Corporate     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
    41,574       140       41,714                   41,714                  
Sales—purchased gas
    41,206             41,206                   41,206                  
Other revenue
    17,268       38       17,306       2,169             19,475                  
Intersegment revenues
    40,992       695       41,687             (41,687 )                      
 
                                                   
Total Revenue and Other Income
  $ 416,858     $ 17,302     $ 434,160     $ 2,169     $ (41,687 )   $ 394,642                  
 
                                                   
Earnings Before Income Taxes
  $ 194,371     $ 3,685     $ 198,056     $ 998     $     $ 199,054       (J)          
 
                                                   
Segment assets
  $ 844,073     $ 51,186     $ 895,259     $ 132,311     $     $ 1,027,570       (K)(L)          
 
                                                   
Depreciation, depletion and amortization
  $ 25,488     $ 1,949     $ 27,437     $     $     $ 27,437                  
 
                                                   
Capital expenditures
  $ 94,424     $ 22,613     $ 117,037     $     $     $ 117,037                  
 
                                                   
 
(J)   Includes equity in earnings (loss) of unconsolidated affiliates of $1,179 and ($452) for Central Appalachia and Corporate Segments, respectively.
 
(K)   Includes investments in unconsolidated equity affiliates of $26,923 and $24,735 for Central Appalachia and Corporate Segments, respectively.
 
(L)   Includes cash of $107,576 in the Corporate Segment.

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Note 8—Recent Accounting Pronouncements:
     In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FAS 115” (SFAS 159). SFAS 159 permits all entities to choose to measure certain eligible assets and liabilities at fair value and would enable entities to mitigate volatility in earnings caused by measuring related assets and liabilities differently. The Statement attempts to improve financial reporting as it establishes presentation and disclosure requirements specific to the fair value method. The required disclosures are aimed at enhancing the comparability of financial information between entities. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Earlier application is permitted provided the entity also elects to apply the provisions of SFAS 157. We do not expect this pronouncement to have a significant impact on CNX Gas.
     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States of America, and requires additional disclosures about fair value measurements. SFAS 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. SFAS 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.
     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. This Statement was adopted by CNX Gas on December 31, 2006. Additionally, SFAS 158 contains another provision which requires an employer to measure the funded status of each of its plans as of the date of its year-end statement of financial position. This provision becomes effective for CNX Gas for its December 31, 2008 year-end. The funded status of CNX Gas’ pension and other postretirement benefit plans are currently measured as of September 30.
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,” “the company” and “CNX Gas” mean CNX Gas Corporation and its consolidated subsidiaries.
Overview
     We are a natural gas exploration, development, production and gathering company with operations in several states in the Appalachian Basin and the Illinois 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 Inc. (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.
     CONSOL Energy continues to beneficially own approximately 81.7% of our outstanding common stock; as such, CNX Gas’ financial statements are consolidated into CONSOL Energy’s financial statements.

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Operations & Outlook
     CNX Gas employees worked another quarter without incurring a lost time accident. This raises the cumulative time worked by employees without a lost time incident to over 2.5 million man hours.
     Quarterly financial results were adversely affected by two items: production and administrative costs. The administrative costs were related to additional litigation costs, as well as consulting costs associated with our new integrated software implementation and the continuing growth of the company from 162 employees on September 30, 2006 to 265 employees on September 30, 2007 as a result of the development of new production plays. Buchanan Mine, the source of some of the company’s lowest cost production, remained idle in the third quarter. In early October, 2007, after the end of a 90-day deductible period, CNX Gas became eligible to file a claim for business interruption insurance as a result of the mine idling.
     During the quarter:
    In our Virginia operations, we drilled 63 wells bringing the nine-month total to 214 wells. As of September 30, Virginia Operations is on schedule to drill its 278 planned wells in 2007. These figures are exclusive of gob wells. CNX Gas is preparing for a 300-well program in Virginia in 2008.
 
    The Mountaineer play in Northern Appalachia is also on schedule, having drilled 45 of the 57 planned wells in 2007, including 21 in the third quarter. Mountaineer now has five rigs running. The average per well peak production from fully de-watered wells continues to meet expectations. Additional rigs are due to arrive in Mountaineer during 2008, with an average rig count for the year expected to be eight. CNX Gas is preparing for a 100-well program in Mountaineer in 2008. Processing plant availability at Mountaineer was at a record high in the third quarter, at 93.5%. The six days of unplanned outages in the third quarter were down from nine days in the second quarter, and 25 in the first quarter. The company remains focused on this issue.
 
    In Nittany, the company’s exploratory CBM play in central Pennsylvania, CNX Gas is advancing the start-up date to November 1. At that time, CNX Gas will flow gas into two compressor stations and a 48,000-foot gathering system. Nittany represents the first totally new step-out opportunity for CNX Gas since its inception in 2005. CNX Gas is actively preparing for a 100-well program in Nittany in 2008 expected to be completed with one or two rigs.
 
    In Cardinal, the company’s exploratory New Albany Shale play in the Illinois Basin, two vertical wells were drilled in western Kentucky. A third vertical well in Kentucky was re-drilled as a horizontal well and fraced using a multi-stage technique. Gas began flowing from that well in mid-October, although it is not tied into production.
     CNX Gas became a registered offset provider on the Chicago Climate Exchange (CCX) within the current quarter. CCX is rules-based Greenhouse Gas (GhG) allowance trading system. CCX emitting members make a voluntary but legally binding commitment to meet annual GhG emission reduction targets. Those emitting members who reduce below the targets have surplus allowances to sell or bank; those who emit above targets comply by purchasing offsets which are called CCX Carbon Financial Instruments (CFI) contracts. As a CCX offset provider, CNX Gas is not bound to any emission reduction targets. An offset provider is an owner of an offset project that registers and sells offsets on its own behalf. In order to sell or trade CFI’s, approval must be received by the CCX Committee on Offsets and approved projects must then be validated by an independent CCX verifier. Once verified, CCX then issues CFI’s for each specific project. As of September 30, 2007, we have initiated the verification process for several projects to convert captured coal mine methane into tradable credits. Credits are granted on the basis of avoiding methane emissions by diverting gas into gas pipelines for commercial sale. No CFI’s have been issued or received as of September 30, 2007; however, we expect approval for these projects will be received during the fourth quarter. Sales of these credits will be reflected in income as they occur. Management is currently formulating its carbon credit strategy.
     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.
     CNX Gas had forecast 2007 production of 60 Bcf. This forecast was predicated on CONSOL Energy re-entering the Buchanan Mine on August 1. The mine, however, remains idle and its return to active status cannot be predicted. If the mine were not to re-start until January 1, CNX Gas would expect fourth quarter production of 14.4 Bcf and calendar year 2007 production of 58 Bcf.

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Results of Operations
Three Months Ended September 30, 2007 compared with Three Months Ended September 30, 2006
(Amounts reported in thousands)
Net Income
     Net income changed due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 96,222     $ 92,507     $ 3,715       4.0 %
Related Party Sales
    2,379       2,719       (340 )     (12.5 )%
Royalty Interest Gas Sales
    10,175       13,221       (3,046 )     (23.0 )%
Purchased Gas Sales
    821       9,076       (8,255 )     (91.0 )%
Other Income
    208       6,044       (5,836 )     (96.6 )%
 
                         
Total Revenue and Other Income
    109,805       123,567       (13,762 )     (11.1 )%
 
                         
Costs and Expenses:
                               
Lifting Costs
    8,588       7,775       813       10.5 %
Gathering and Compression Costs
    15,283       14,646       637       4.3 %
Royalty Interest Gas Costs
    8,543       10,808       (2,265 )     (21.0 )%
Purchased Gas Costs
    495       9,340       (8,845 )     (94.7 )%
Other
    (1,363 )     1,021       (2,384 )     (233.5 )%
General and Administrative
    12,793       8,634       4,159       48.2 %
Depreciation, Depletion and Amortization
    12,248       9,546       2,702       28.3 %
Interest Expense
    1,221             1,221       100.0 %
 
                         
Total Costs and Expenses
    57,808       61,770       (3,962 )     (6.4 )%
 
                         
Earnings Before Income Taxes
    51,997       61,797       (9,800 )     (15.9 )%
Income Taxes
    20,701       24,204       (3,503 )     (14.5 )%
 
                         
Net Income
  $ 31,296     $ 37,593     $ (6,297 )     (16.8 )%
 
                         
     Net income for 2007 was lower primarily due to deferred production from the Buchanan Mine incident, partially offset by new wells being brought on-line. Higher lifting, gathering, administrative costs and depreciation also contributed to a lower net income, despite improved average sales prices. Finally, insurance proceeds realized in the prior period were not received in the current period.
Revenue and Other Income
     Revenue and other income decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 96,222     $ 92,507     $ 3,715       4.0 %
Related Party Sales
    2,379       2,719       (340 )     (12.5 )%
Royalty Interest Gas Sales
    10,175       13,221       (3,046 )     (23.0 )%
Purchased Gas Sales
    821       9,076       (8,255 )     (91.0 )%
Other Income
    208       6,044       (5,836 )     (96.6 )%
 
                         
Total Revenue and Other Income
  $ 109,805     $ 123,567     $ (13,762 )     (11.1 )%
 
                         
     The decrease in total revenue and other income was primarily due to decreased purchased gas sales as a result of the adoption of an accounting change combined with decreased other income related to insurance settlements received in 2006.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    14.3       14.4       (0.1 )     (0.7 )%
Average Sales Price (per Mcf)
  $ 6.87     $ 6.62     $ 0.25       3.8 %
     The slight increase in average sales price is the result of CNX Gas realizing higher hedging gains. CNX Gas periodically enters

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into various gas swap transactions that qualify as financial cash flow hedges for terms varying in length. These gas swap transactions exist parallel to the underlying physical transactions. For the three months ended September 30, 2007, these financial hedges represented approximately 4.7 Bcf of gas sales volumes at an average price of $8.00 per Mcf, compared to approximately 4.7 Bcf at an average price of $7.73 per Mcf for the three months ended September 30, 2006. Also included within the 2007 period are the non-operated net revenue interest volumes and revenues associated with royalty and working interests; these volumes were not available in the 2006 period while the associated revenues were included in other income.
                                 
                            Percentage
    2007   2006   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    1.8       1.9       (0.1 )     (5.3 )%
Average Sales Price (per Mcf)
  $ 5.81     $ 6.85     $ (1.04 )     (15.2 )%
     For accounting purposes, 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 decrease in average sales price relates to the volatility in the monthly volumes, contractual differences among leases, as well as the mix of average and index prices used in calculating royalties.
                                 
                            Percentage
    2007   2006   Variance   Change
Purchased Gas Sales Volumes (Bcf)
    0.1       1.4       (1.3 )     (92.9 )%
Average Sales Price (per Mcf)
  $ 6.13     $ 6.45     $ (0.32 )     (5.0 )%
     Purchased gas sales volumes in the current period represent volumes of gas we sell at market prices that were purchased from third party producers, less our gathering fees. In the 2006 period, purchased gas sales and volumes represented volumes of gas we simultaneously purchased from and sold to the same counterparties under contracts that were committed prior to January 1, 2006. Accordingly, Emerging Issues Task Force Issue No. 04-13 (EITF 04-13), which we adopted on January 1, 2006, did not apply to these transactions. All contracts entered into prior to January 1, 2006 have now expired and new contracts are reflected in transportation expense on a net basis.
     Other income consists of the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Interest Income
  $ 630     $ 1,071     $ (441 )     (41.2 )%
Other Miscellaneous
    24       (159 )      183       115.1 %
Third Party Gathering Revenue
    (446 )      391       (837 )     (214.1 )%
Insurance Settlements
          2,121       (2,121 )     (100.0 )%
Royalty Income
          2,620       (2,620 )     (100.0 )%
 
                         
Total Other Income
  $ 208     $ 6,044     $ (5,836 )     (96.6 )%
 
                         
     Interest income decreased in 2007 as a result of a decreased average daily cash balance from the prior period.
     Other miscellaneous income increased due to various transactions, none of which are individually material throughout both periods.
     Third party gathering revenue decreased in 2007 due to the termination of our principal third party gathering agreement and the associated final settlement.
     In the prior year, the insurance settlements component of other income consisted 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, is now classified in outside sales. In the prior period, the volumes were not available nor were they considered in the prior period reserve report. In the current period, these volumes are included in both sales production and reserves.

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Costs and Expenses
     Costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Costs and Expenses:
                               
Lifting Costs
  $ 8,588     $ 7,775     $ 813       10.5 %
Gathering and Compression Costs
    15,283       14,646        637       4.3 %
Royalty Interest Gas Costs
    8,543       10,808       (2,265 )     (21.0 )%
Purchased Gas Costs
     495       9,340       (8,845 )     (94.7 )%
Other
    (1,363 )     1,021       (2,384 )     (233.5 )%
General and Administrative
    12,793       8,634       4,159       48.2 %
Depreciation, Depletion and Amortization
    12,248       9,546       2,702       28.3 %
Interest Expense
    1,221             1,221       100.0 %
 
                         
Total Costs and Expenses
  $ 57,808     $ 61,770     $ (3,962 )     (6.4 )%
 
                         
     The decrease in total costs and expenses was primarily due to decreased purchased gas costs, offset by increased administrative costs and depreciation.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    14.3       14.4       (0.1 )     (0.7 )%
Average Lifting Costs (per Mcf)
  $ 0.60     $ 0.54     $ 0.06       11.1 %
     Lifting costs per unit sold increased primarily due to increased well service and maintenance costs related to the increased number of wells in the period combined with the additional service rigs employed. These cost increases were partially offset by a decrease to expense as a result of an adjustment to the well plugging liability as well as reduced water disposal costs.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    14.3       14.4       (0.1 )     (0.7 )%
Average Gathering and Compression Costs (per Mcf)
  $ 1.07     $ 1.02     $ 0.05       4.9 %
     The increase in gathering and compression unit costs was attributable to higher maintenance costs resulting from the increased number of wells in the period, increased compressor rental costs related to the infrastructure development in Mountaineer, and additional gob collection costs. These increases were offset by lower firm transportation costs due to the in-service of the Jewell Ridge lateral in October 2006 and lower power costs as a result of a rate adjustment for the entire year being credited within the quarter.
                                 
                            Percentage
    2007   2006   Variance   Change
Royalty Interest Gas Cost Volumes (Bcf)
    1.8       1.9       (0.1 )     (5.3 )%
Average Cost (per Mcf)
  $ 4.88     $ 5.60     $ (0.72 )     (12.9 )%
     For accounting purposes, 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 relates to the volatility in the monthly volumes as well as the mix of average and index prices used in calculating royalties.
                                 
                            Percentage
    2007   2006   Variance   Change
Purchased Gas Cost Volumes (Bcf)
    0.1       1.4       (1.3 )     (92.9 )%
Average Purchased Gas Costs (per Mcf)
  $ 4.76     $ 6.64     $ (1.88 )     (28.3 )%
     Purchased gas cost volumes in the current period represent volumes of gas we sell at market prices that were purchased from third party producers, less our gathering and marketing fees. In the 2006 period, purchased gas sales and volumes represented volumes of gas we simultaneously purchased from and sold to the same counterparties under contracts that were committed prior to January 1, 2006. Accordingly, Emerging Issues Task Force Issue No. 04-13 (EITF 04-13), which we adopted on January 1, 2006, did not apply to these transactions. All contracts entered into prior to January 1, 2006 have now expired and new contracts are reflected in transportation expense on a net basis. Purchased gas costs also includes the reversing affect of a June 2007 pipeline imbalance.

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Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CNX Gas is responsible for monitoring this imbalance and adjusting contracted volumes as circumstances warrant. As of June 30, 2007, CNX Gas showed an under-delivered position to the pipeline resulting in the inclusion of the imbalance in Purchased Gas costs. As of September 30, 2007, we are in an over-delivered position and have included the imbalance in Outside Sales. This inclusion of imbalance income resulted in a minimal increase to Outside Sales.
     Other costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Exploration
  $ (436 )   $ 687     $ (1,123 )     (163.5 )%
Imbalance
           289       (289 )     (100.0 )%
Equity in (Earnings) Loss of Affiliates
    (927 )     45       (972 )     (2,160.0 )%
 
                         
Total Other Costs and Expenses
  $ (1,363 )   $ 1,021     $ (2,384 )     (233.5 )%
 
                         
     Exploration costs have decreased due to an adjustment of core hole costs to capital in the period. The imbalance is included in outside sales in the 2007 period. Additionally, equity in (earnings) loss of affiliates increased in 2007 compared to 2006, primarily due to increased power plant operating hours in our Buchanan Generation joint venture.
     General and administrative costs increased in the quarter to $12,793 in 2007 from $8,634 in 2006 primarily due to additional litigation costs, the continued increase in staffing as a result of the continuing growth of the company from 162 employees on September 30, 2006 to 265 employees on September 30, 2007, as well as an increase in related long term incentive compensation costs.
     Depreciation, depletion and amortization have increased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Production
  $ 7,764     $ 6,357     $ 1,407       22.1 %
Gathering
    4,484       3,189       1,295       40.6 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 12,248     $ 9,546     $ 2,702       28.3 %
 
                         
     The increase in production related depreciation, depletion and amortization was primarily due to the increase in units of production rates period to period. These rates, which are recalculated annually, increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased primarily as a result of the capital lease treatment of the Jewell Ridge lateral, which went into service in October of 2006.
     Interest expense increased as a result of our capital lease obligation on the Jewell Ridge pipeline, which went into service on October 28, 2006.
Income Taxes
                                 
                            Percentage
    2007   2006   Variance   Change
Earnings Before Income Taxes
  $ 51,997     $ 61,797     $ (9,800 )     (15.9 )%
Tax Expense
  $ 20,701     $ 24,204     $ (3,503 )     (14.5 )%
Effective Income Tax Rate
    39.8 %     39.2 %     0.6 %        
     CNX Gas’ effective tax rate increased in the period primarily due to a slight increase in the state tax rate related to state apportionment factors and the impact of the manufacturer’s deduction.

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Results of Operations
Nine Months Ended September 30, 2007 compared with Nine Months Ended September 30, 2006
(Amounts reported in thousands)
Net Income
     Net income changed due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 306,615     $ 286,494     $ 20,121       7.0 %
Related Party Sales
    6,980       5,753       1,227       21.3 %
Royalty Interest Gas Sales
    36,841       41,714       (4,873 )     (11.7 )%
Purchased Gas Sales
    3,297       41,206       (37,909 )     (92.0 )%
Other Income
    4,675       19,475       (14,800 )     (76.0 )%
 
                         
Total Revenue and Other Income
    358,408       394,642       (36,234 )     (9.2 )%
 
                         
Costs and Expenses:
                               
Lifting Costs
    25,617       24,115       1,502       6.2 %
Gathering and Compression Costs
    46,593       43,021       3,572       8.3 %
Royalty Interest Gas Costs
    31,736       34,491       (2,755 )     (8.0 )%
Purchased Gas Costs
    2,987       42,091       (39,104 )     (92.9 )%
Other  
    228        783       (555 )     (70.9 )%
General and Administrative
    39,069       23,641       15,428       65.3 %
Depreciation, Depletion and Amortization
    36,325       27,437       8,888       32.4 %
Interest Expense
    3,686       9       3,677       40,855.6 %
 
                         
Total Costs and Expenses
    186,241       195,588       (9,347 )     (4.8 )%
 
                         
Earnings Before Income Taxes
    172,167       199,054       (26,887 )     (13.5 )%
Income Taxes
    66,387       77,432       (11,045 )     (14.3 )%
 
                         
Net Income
  $ 105,780     $ 121,622     $ (15,842 )     (13.0 )%
 
                         
     Net income for 2007 was lower primarily due to deferred production from the Buchanan Mine incident, partially offset by new wells being brought on-line, no insurance proceeds in the current period as compared to 2006 and higher administrative and operating costs.
Revenue and Other Income
     Revenue and other income decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Revenue and Other Income:
                               
Outside Sales
  $ 306,615     $ 286,494     $ 20,121       7.0 %
Related Party Sales
    6,980       5,753       1,227       21.3 %
Royalty Interest Gas Sales
    36,841       41,714       (4,873 )     (11.7 )%
Purchased Gas Sales
    3,297       41,206       (37,909 )     (92.0 )%
Other Income
    4,675       19,475       (14,800 )     (76.0 )%
 
                         
Total Revenue and Other Income
  $ 358,408     $ 394,642     $ (36,234 )     (9.2 )%
 
                         
     The decrease in total revenue and other income was primarily due to the accounting change related to purchased gas sales and no insurance proceeds in the current period.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    43.4       41.7       1.7       4.1 %
Average Sales Price (per Mcf)
  $ 7.22     $ 7.01     $ 0.21       3.0 %
     The slight increase in average sales price is the result of CNX Gas realizing higher hedging gains. CNX Gas periodically enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the

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underlying physical transactions. For the nine months ended September 30, 2007, these physical and financial hedges represented approximately 12.7 Bcf of our gas sales volumes at an average price of $7.95 per Mcf, compared to approximately 13.0 Bcf at an average price of $7.49 per Mcf for the nine months ended September 30, 2006. Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Also included within the 2007 period are the non-operated net revenue interest volumes and revenues associated with royalty and working interests; these volumes were not available in the 2006 period while the associated revenues were included in other income.
                                 
                            Percentage
    2007   2006   Variance   Change
Royalty Interest Sales Volumes (Bcf)
    5.4       5.6       (0.2 )     (3.6 )%
Average Sales Price (per Mcf)
  $ 6.77     $ 7.42     $ (0.65 )     (8.8 )%
     For accounting purposes, 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 decrease in average sales price relates to the volatility in the monthly volumes, contractual differences among leases, as well as the mix of average and index prices used in calculating royalties.
                                 
                            Percentage
    2007   2006   Variance   Change
Purchased Gas Sales Volumes (Bcf)
    0.5       5.4       (4.9 )     (90.7 )%
Average Sales Price (per Mcf)
  $ 6.90     $ 7.67     $ (0.77 )     (10.0 )%
     Purchased gas sales volumes in the current period represent volumes of gas we sell at market prices that were purchased from third party producers, less our gathering and marketing fees. In the 2006 period, purchased gas sales and volumes represented volumes of gas we simultaneously purchased from and sold to the same counterparties under contracts that were committed prior to January 1, 2006. Accordingly, Emerging Issues Task Force Issue No. 04-13 (EITF 04-13), which we adopted on January 1, 2006, did not apply to these transactions. All contracts entered into prior to January 1, 2006 have now expired and new contracts are reflected in transportation expense on a net basis.
     Other income consists of the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Interest Income
  $ 3,363     $ 2,169     $ 1,194       55.0 %
Third Party Gathering Revenue
    1,171       1,057        114       10.8 %
Other Miscellaneous  
    141       (37 )      178       481.1 %
Insurance Settlements
    0       9,088       (9,088 )     (100.0 )%
Royalty Income
    0       7,198       (7,198 )     (100.0 )%
 
                         
Total Other Income
  $ 4,675     $ 19,475     $ (14,800 )     (76.0 )%
 
                         
     Interest income increased in 2007 as a result of a higher cash balance throughout a majority of the reporting period.
     Third party gathering revenue was higher due to an increase in the gathering rates CNX Gas charged its customers in 2007 compared to 2006, which was partially offset by actualizations associated with the termination and final settlement of our principal third party gathering agreements.
     Other miscellaneous income increased due to various transactions, none of which are individually material throughout both periods.
     In the prior year, the insurance settlements component of other income consisted 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, is now classified in outside sales. In the prior period, the volumes were not available nor were they considered in the prior period reserve report. In the current period, these volumes are included in both sales production and reserves.

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Costs and Expenses
     Costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Costs and Expenses:
                               
Lifting Costs
  $ 25,617     $ 24,115     $ 1,502       6.2 %
Gathering and Compression Costs
    46,593       43,021       3,572       8.3 %
Royalty Interest Gas Costs
    31,736       34,491       (2,755 )     (8.0 )%
Purchased Gas Costs
    2,987       42,091       (39,104 )     (92.9 )%
Other
    228        783       (555 )     (70.9 )%
General and Administrative
    39,069       23,641       15,428       65.3 %
Depreciation, Depletion and Amortization
    36,325       27,437       8,888       32.4 %
Interest Expense
    3,686       9       3,677       40,855.6 %
 
                         
Total Costs and Expenses
  $ 186,241     $ 195,588     $ (9,347 )     (4.8 )%
 
                         
     The decrease in total costs and expenses was primarily due to the accounting change related to purchased gas costs, offset by increased depreciation and administrative costs.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    43.4       41.7       1.7       4.1 %
Average Lifting Costs (per Mcf)
  $ 0.59     $ 0.58     $ 0.01       1.7 %
     Lifting costs per unit sold increased primarily due to increased well service and maintenance costs related to the increased number of wells in the period combined with the additional service rigs employed. These cost increases were partially offset by a decrease to expense as a result of an adjustment to the well plugging liability.
                                 
                            Percentage
    2007   2006   Variance   Change
Sales Volumes (Bcf)
    43.4       41.7       1.7       4.1 %
Average Gathering and Compression Costs (per Mcf)
  $ 1.07     $ 1.03     $ 0.04       3.9 %
     The increase in gathering and compression unit costs was attributable to additional maintenance and compressor rental costs related to the increased number of wells in the period as well as higher power expenses related to increased megawatt hour rates charged by the power company. These increases were offset by lower firm transportation costs due to the in-service of the Jewell Ridge lateral in October 2006.
                                 
                            Percentage
    2007   2006   Variance   Change
Royalty Interest Gas Cost Volumes (Bcf)
    5.4       5.6       (0.2 )     (3.6 )%
Average Cost (per Mcf)
  $ 5.83     $ 6.13     $ (0.30 )     (4.9 )%
     For accounting purposes, 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 relates to the volatility in the monthly volumes as well as the mix of average and index prices used in calculating royalties.
                                 
                            Percentage
    2007   2006   Variance   Change
Purchased Gas Cost Volumes (Bcf)
    0.5       5.4       (4.9 )     (90.7 )%
Average Purchased Gas Costs (per Mcf)
  $ 6.09     $ 7.84     $ (1.75 )     (22.3 )%
     Purchased gas cost volumes in the current period represent volumes of gas we sell at market prices that were purchased from third party producers, less our gathering and marketing fees. In the 2006 period, purchased gas sales and volumes represented volumes of gas we simultaneously purchased from and sold to the same counterparties under contracts that were committed prior to January 1, 2006. Accordingly, Emerging Issues Task Force Issue No. 04-13 (EITF 04-13), which we adopted on January 1, 2006, did not apply to these transactions. All contracts entered into prior to January 1, 2006 have now expired and new contracts are reflected in

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transportation expense on a net basis.
     Other costs and expenses decreased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Exploration
  $ 1,558     $ 2,092     $ (534 )     (25.5 )%
Imbalance
          (582 )      582       100.0 %
Equity in (Earnings) of Affiliates
    (1,330 )     (727 )     (603 )     (82.9 )%
 
                         
Total Other Costs and Expenses
  $ 228     $ 783     $ (555 )     (70.9 )%
 
                         
     Exploration costs have decreased due to a larger portion of exploration activity being capitalized in the current year as compared to the prior year. The imbalance is now included in outside sales. Additionally, equity in (earnings) of affiliates increased in 2007 compared to 2006, primarily due to increased production from our Knox Energy joint venture.
     General and administrative costs increased to $39,069 in 2007 from $23,641 in 2006 primarily due to increased litigation costs, additional consulting costs associated with our new integrated software implementation, the continued increase in staffing as a result of the continuing growth of the company from 162 employees on September 30, 2006 to 265 employees on September 30, 2007 as well as an increase in related long term incentive compensation costs.
     Depreciation, depletion and amortization have increased due to the following items:
                                 
                    Dollar     Percentage  
    2007     2006     Variance     Change  
Production
  $ 22,793     $ 18,002     $ 4,791       26.6 %
Gathering
    13,532       9,435       4,097       43.4 %
 
                         
Total Depreciation, Depletion and Amortization
  $ 36,325     $ 27,437     $ 8,888       32.4 %
 
                         
     The increase in production related depreciation, depletion and amortization was primarily due to increased production combined with the increase in units of production rates period to period. These rates, which are recalculated annually, increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased primarily as a result of the capital lease treatment of the Jewell Ridge lateral, which went into service in October of 2006.
     Interest expense increased as a result of our capital lease obligation on the Jewell Ridge pipeline, which went into service on October 28, 2006.
Income Taxes
                                 
                            Percentage
    2007   2006   Variance   Change
Earnings Before Income Taxes
  $ 172,167     $ 199,054     $ (26,887 )     (13.5 )%
Tax Expense
  $ 66,387     $ 77,432     $ (11,045 )     (14.3 )%
Effective Income Tax Rate
    38.6 %     38.9 %     (0.3 )%        
     CNX Gas’ effective tax rate decreased in 2007 primarily due to a slight decrease in the net effect of state income taxes and the impact of the manufacturer’s deduction.
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 credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. No borrowings are outstanding under our credit facility at September 30, 2007.
     CNX Gas and our subsidiaries guarantee CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of

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approximately $250,000.
     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 $13,454 at September 30, 2007. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings in the three months and nine months ended September 30, 2007.
Cash Flows
                         
    Year to Date   Year to Date    
    2007   2006   Change
Cash provided by operating activities
  $ 211,075     $ 205,943     $ 5,132  
Cash (used in) investing activities
  $ (267,188 )   $ (118,440 )   $ (148,748 )
Cash provided by financing activities
  $ 7,343     $     $ 7,343  
    Cash provided by operating activities increased due to various changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods, partially offset by a decrease in net income.
 
    Cash used in investing activities increased due to our expanded capital program, including the acquisition of Peabody gas assets.
 
    Cash provided by financing activities increased primarily due to the debt of the third party contractor rigs, which were consolidated under FIN 46.
Contractual Commitments
     The following is a summary of our significant contractual obligations at September 30, 2007. We estimate payments, net of any applicable reimbursements, related to these items at September 30, 2007 to be as follows:
                                         
            Within     1-3     3-5     More than  
    Total     1 Year     Years     Years     5 Years  
Long Term Debt Obligations (a)
  $ 9,000     $ 2,760     $ 6,240     $     $  
Capital (Finance) Lease Obligations (b)
    64,557       2,719       6,076       7,036       48,726  
Operating Lease Obligations
    7,359       1,512       2,578       1,963       1,306  
Other Long-Term Liabilities:
                                       
Gas Firm Transportation Obligation
    50,655       7,392       14,554       10,482       18,227  
Other Liabilities (c)
    15,612                         15,612  
Well Plugging Liabilities
    3,402              333        604       2,465  
Pension
     105       3       13       23       66  
Postretirement Benefits Other than Pension
    2,447       11       68        154       2,214  
 
                             
Total Contractual Obligations (d)
  $ 153,137     $ 14,397     $ 29,862     $ 20,262     $ 88,616  
 
                             
 
(a)   The long term debt obligation relates to the debt of a third party contractor guaranteed by CNX Gas and consolidated as a variable interest entity. See Note 6 for further information.
 
(b)   In conjunction with the completion of the Jewell Ridge lateral in October 2006, CNX Gas entered into a 15 year firm transportation agreement with East Tennessee Natural Gas (ETNG), a subsidiary of Spectra Energy, at pre-determined fixed rates. The present value of our payments under this firm transportation agreement is approximately $64,557. 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.
 
(c)   This item represents legal contingencies reflected on the balance sheet for potential settlements for two of the cases referenced in

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    Note 6 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.
 
(d)   The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
     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.
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, 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 and 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 to 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, including our inability to retain and attract key personnel;
 
    increased costs;
 
    the effects of government regulation and permitting and other legal requirements;
 
    legal uncertainties relating to the ownership of the coalbed methane state, and costs associated with perfecting title for gas rights in some of our properties;

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    litigation concerning real property rights, intellectual property rights, and royalty calculations;
 
    our relationships and arrangements with CONSOL Energy; and
 
    other factors discussed under “Risk Factors” in the 10-K for the year ended December 31, 2006.
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 on Form 10-K for the year ended December 31, 2006.
     Sensitivity analyses of the incremental effects on future pre-tax income of a hypothetical 10% and 25% increase in natural gas prices for open derivative instruments as of September 30, 2007 are provided in the following table:
                 
    Incremental decrease in pre-tax income assuming a
    Hypothetical price increase of:
    10%   25%
    (In millions)
Natural Gas (1)
  $ 27.9     $ 70.4  
 
(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 2007 through 2009 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, 2007, the fair value of these contracts was a net gain of $8,221 (net of $5,233 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 October 17, 2007, 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
2007 Fixed Price Volumes
                                       
Hedged Mcf
    3,247,423       4,690,722       4,742,268       5,685,566       18,365,979  
Weighted Average Hedge Price/Mcf
  $ 7.77     $ 8.00     $ 8.00     $ 8.18     $ 8.02  
2008 Fixed Price Volumes
                                       
Hedged Mcf
    6,097,938       6,097,939       6,164,948       6,164,948       24,525,773  
Weighted Average Hedge Price/Mcf
  $ 8.39     $ 8.24     $ 8.29     $ 8.29     $ 8.30  
2009 Fixed Price Volumes
                                       
Hedged Mcf
    4,175,258       1,407,216       1,422,681       479,381       7,484,536  
Weighted Average Hedge Price/Mcf
  $ 8.82     $ 8.08     $ 8.15     $ 8.06     $ 8.51  
     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 any 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, 2007 to ensure that information required to be disclosed by CNX Gas in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
     Changes in Internal Controls Over Financial Reporting.
     There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
     The first through seventh paragraphs of Note 6 — Commitments and Contingent Liabilities in the notes to the Consolidated Financial Statements included in Part I of this Form 10-Q are incorporated herein by reference.
ITEM 1A. RISK FACTORS
     No material changes from our most recently filed Annual Report on Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
     None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     None
ITEM 5. OTHER INFORMATION
     None
ITEM 6. EXHIBITS
     
3.1
  Second Amended and Restated Bylaws of CNX Gas Corporation are incorporated herein by reference from Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on August 16, 2007.
 
   
10.1
  Offer letter to Dr. DeAnn Craig dated June 18, 2007
 
   
10.2
  Schedule of Compensation of Non-Employee Directors.
 
   
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.

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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: October 30, 2007
         
  CNX Gas Corporation
 
 
  By:   /s/ Nicholas J. DeIuliis    
    Nicholas J. DeIuliis   
    President and Chief Executive Officer
(Duly Authorized Officer) 
 
 
     
  By:   /s/ Mark D. Gibbons    
    Mark D. Gibbons   
    Senior Vice President and Chief Financial Officer
(Principal Financial Officer) 
 
 

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EXHIBIT INDEX
     
3.1
  Second Amended and Restated Bylaws of CNX Gas Corporation are incorporated herein by reference from Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on August 16, 2007.
 
   
10.1
  Offer letter to Dr. DeAnn Craig dated June 18, 2007
 
   
10.2
  Schedule of Compensation of Non-Employee Directors.
 
   
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.

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