Annual Reports

 
Quarterly Reports

 
8-K

 
Other

CNX Gas 10-K 2008
CNX GAS CORPORATION 110-K
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
     
(Mark One)    
 
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
    For the fiscal year ended December 31, 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
 
 
 
 
     
Delaware   20-3170639
(State or Other Jurisdiction of
Incorporation or Organization)
  (I.R.S. Employer
Identification No.)
5 Penn Center West, Suite 401
Pittsburgh, PA 15276-0102
(412) 200-6700
(Address, including zip code, and telephone number,
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock ($.01 par value)   New York Stock Exchange
No securities are registered pursuant to Section 12(g) of the Act.
 
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):
 
             
Large accelerated filer þ
       Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act).  Yes o     No þ
 
The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2007, based on the closing price of the common stock on the New York Stock Exchange on such date ($30.60 per share), was $853,531,828. For purposes of determining this amount, affiliates include directors and executive officers, who, as of June 30, 2007, in the aggregate held 85,062 shares (including shares held in 401(k) plans, shares held by trusts with respect to which the director or executive officer was trustee, and shares held jointly with a spouse, but not including shares underlying vested options or vested restricted stock units), and CONSOL Energy Inc., which held 122,896,667 shares.
 
The number of shares outstanding of the registrant’s common stock as of January 31, 2008 is 150,916,698 shares.
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of CNX Gas Corporation’s Proxy Statement for the Annual Meeting of Stockholders to be held on April 21, 2008, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III
 


 

 
 
                 
        Page
 
      Business     4  
      Risk Factors     20  
      Unresolved Staff Comments     31  
      Properties     31  
      Legal Proceedings     31  
      Submission of Matters to a Vote of Security Holders     31  
 
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     31  
      Selected Financial Data     34  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     37  
      Quantitative and Qualitative Disclosures About Market Risk     55  
      Financial Statements and Supplementary Data     57  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosures     98  
      Controls and Procedures     98  
      Other Information     98  
 
      Directors and Executive Officers of the Registrant     99  
      Executive Compensation     100  
      Security Ownership of Certain Beneficial Owners and Management     100  
      Certain Relationships and Related Transactions     101  
      Principal Accounting Fees and Services     101  
 
      Exhibits and Financial Statement Schedules     101  
    102  
 EX-10.45
 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-31.2
 EX-32.1
 ex-32.2


2


Table of Contents

 
We are including the following cautionary statement in this Annual Report on Form 10-K 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 Annual Report on Form 10-K 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 Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; 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;
 
  •  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 regarding the ownership of the coalbed methane estate, and costs associated with perfecting title for gas rights in some of our properties;
 
  •  litigation concerning real property rights, intellectual property rights, royalty calculations and other matters;
 
  •  our relationships and arrangements with CONSOL Energy; and
 
  •  other factors discussed under “Risk Factors.”


3


Table of Contents

 
 
ITEM 1.   BUSINESS
 
Except as otherwise noted or unless the context otherwise requires, (i) the information in this Annual Report on Form 10-K gives effect to the contribution to CNX Gas of the CONSOL Energy gas business effective as of August 8, 2005, (ii) CNX Gas refers, with respect to any date prior to the effective date of that contribution, to the CONSOL Energy gas business and, with respect to any date on or subsequent to the effective date of the contribution, to CNX Gas and our subsidiaries, (iii) “CONSOL Energy” refers to CONSOL Energy Inc. and its subsidiaries other than CNX Gas and the companies which conducted CONSOL Energy’s gas business, and (iv) reserve and operating data are as of December 31, 2007 unless otherwise indicated. The estimates of our proved reserves as of December 31, 2007, 2006, and 2005 included in this Annual Report are based on reserve reports prepared by Schlumberger Data and Consulting Services. The estimates of our proved reserves as of December 31, 2004 and 2003 (set forth in Item 6, “Selected Financial Data — Other Financial Data”) are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. Unless otherwise noted, we discuss production, per unit revenue and per unit costs net of any royalty owners’ interest. With respect to production and reserves, we use the word “net” to indicate when a number does not include the royalty owners’ interest. With respect to acres, we use the word “net” to describe our aggregate fractional interest in property that we control by deed or lease. With the exception of earnings per share data, we discuss dollars in thousands throughout this Form 10-K. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, for the twelve months ended December 31, 2007, 2006 and 2005 is included in Note 18 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.
 
 
We are engaged in the exploration, development, production and gathering of natural gas primarily in the Appalachian and Illinois Basins. In particular, we are a leading developer of coalbed methane (CBM) and are beginning to assess multiple shale plays in emerging areas. CONSOL Energy Inc. (CONSOL Energy) owns 81.7% of our outstanding common stock. In August 2005, we acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other western basins. As of December 31, 2007, we had 1.343 Tcfe of net proved reserves, including our portion of equity affiliates, with a PV-10 value of $2,287,427 and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of $1,389,540. Our proved reserves are approximately 99% CBM and 50% proved developed. We are one of the largest gas producers in the Appalachian Basin with net sales of 58.2 Bcf for the twelve months ended December 31, 2007. Our proved reserves are long-lived with a reserve life index of 23.1 years.
 
 
We began extracting CBM in the early 1980s from coal seams in Virginia in order to reduce the gas content in the coal being mined by CONSOL Energy. We developed techniques to extract CBM from coal seams prior to mining in order to enhance the safety and efficiency of CONSOL Energy’s mining operations. Typically, the gas was vented to the atmosphere. As a result of our more than 20 years of experience with CBM extraction, we believe our management has developed industry-leading expertise in this type of gas production.
 
In 1990, CONSOL Energy created a joint venture with Conoco Inc. (“Conoco”) to produce CBM that qualified for certain preferential tax treatment. Under an operating arrangement, CONSOL Energy operated gas wells and gathering facilities in which Conoco had an ownership interest. In 1993, CONSOL Energy acquired the assets of Island Creek Coal Company in Virginia, including an interest in CBM and gathering assets, from Occidental Petroleum (“Occidental”). The related gas assets acquired from Occidental were sold to MCN Energy Group Inc. (“MCN”) in 1995, although CONSOL Energy continued to operate gas wells in the area for MCN under an operating agreement.


4


Table of Contents

Between 2000 and 2001, CONSOL Energy reacquired the assets of MCN and acquired the interests of our joint venture partner, Conoco, to consolidate our interest in Central Appalachia. This created the core of our business.
 
CNX Gas Corporation (CNX Gas) was formed on June 30, 2005. CONSOL Energy contributed its gas assets to CNX Gas effective August 8, 2005.
 
Our common stock commenced trading on the New York Stock Exchange (“NYSE”) under the symbol “CXG” on January 19, 2006.
 
On January 29, 2008, CONSOL Energy announced an intention to commence an exchange offer to acquire the 18.3% of outstanding shares of CNX Gas that CONSOL Energy does not currently own.
 
 
Prior to August 2005, we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy, a public company traded on the NYSE under the symbol “CNX.” Those companies include: CNX Gas Company, LLC; Cardinal States Gathering Company (“CSGC”); a 50.0% interest in Coalfield Pipeline Company; a working interest in Knox Energy, LLC; a 50.0% interest in Buchanan Generation, LLC; and various other joint ventures. These are the companies primarily responsible for the exploration, production, gathering and sale of our gas, with the exception of Buchanan Generation, LLC, which uses our gas to generate electricity from a generating facility located near our Virginia gas field. CONSOL Energy owned 81.7% of the outstanding common stock of CNX Gas as of December 31, 2007.
 
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 CNX Gas various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM, natural gas, oil, and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with its coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements under which CONSOL Energy will provide us certain corporate staff services and coordinate our tax filings.
 
We have made every effort to preserve the synergies that exist between CONSOL Energy’s mining activities and our gas production activities. Additionally, the master cooperation and safety agreement between us and CONSOL Energy will ensure that we continue to have access to gob gas and gas produced from horizontal wells drilled from inside CONSOL Energy’s mines. These additional sources of gas enhance our overall recovery rates for CBM.
 
 
Approximately 27% of our current gas production is produced in connection with coal extraction by CONSOL Energy. It is essential that gas liberated by the mining process be removed from the mine in order to maintain a safe working environment in the mine. As a result, a portion of our gas extraction activity is determined based upon the needs of the related mining activity.
 
Through close cooperation and coordination between CNX Gas and CONSOL Energy, we prepare an annual drilling program that meets the needs of both companies. The master cooperation and safety agreement provides that each year, in consultation with CONSOL Energy, CNX Gas will outline its drilling plans to show: (i) the general area of development and exploration drilling and the number of wells proposed to be drilled in the following calendar year, and (ii) the approximate location of all production, treatment and gathering related systems proposed to be installed by CNX Gas.
 
 
We primarily produce CBM, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in


5


Table of Contents

commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. We believe that this contributes to lower exploration costs for CNX Gas than those incurred by producers that operate in deeper, less defined formations; however, we intend to increase our exploration efforts in the shale and deeper formations.
 
 
In the Appalachian Basin we operate principally in Central Appalachia and Northern Appalachia, which represent our two reportable segments. We also operate in the Illinois Basin. The five areas we see playing prominent roles in our portfolio in the near future are as follows:
 
  •  first, in Central Appalachia, Virginia Operations CBM, our traditional and largest area of operation, where we have typically produced CBM from vertical wells which we drill ahead of mining and gob gas wells;
 
  •  second, in Northern Appalachia, the Mountaineer CBM play in northwestern West Virginia and southwestern Pennsylvania where our first major drilling program using vertical-to-horizontal well designs is into full scale development;
 
  •  third, in Northern Appalachia, the Nittany CBM play in central Pennsylvania where we have substantial holdings and transitioned initial exploratory testing activities into full scale development;
 
  •  fourth, in the Illinois Basin, Cardinal, the New Albany shale play in western Kentucky, Indiana and Illinois which has economic potential where we are in the midst of exploratory testing activities; and
 
  •  last, in addition to the above areas, we believe we have Appalachian shale potential in the Marcellus, Huron, and Chattanooga shales. Additional potential exists in the Trenton Black River formation which is thought to underlie nearly all of the Appalachian shales. We will continue to evaluate our acreage position in these areas, with the commencement of an exploration program in 2008.
 
Central Appalachia
 
 
We have the right to extract CBM in this region from approximately 368,000 net CBM acres, which cover a portion of coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We acquired CONSOL Energy’s rights associated with CBM in this region upon inception. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas per ton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
 
We coordinate some of our CBM extraction with the subsurface coal mining of CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam ahead of the planned mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” In 2007, frac wells account for approximately 73.0% of our daily Virginia production.
 
Because some of our gas is produced in association with subsurface mining, we have a unique opportunity to evaluate the effectiveness of our fracture techniques. We can enter the coal mine and inspect the fracture pattern created in the seam as the mining process exposes more of the coal. As a result, we have had the


6


Table of Contents

opportunity to gain insight into the efficiency of our fracturing techniques that is not available in a conventional production scenario. We have used this knowledge to modify and improve the effectiveness of our fracturing techniques.
 
Eventually, subsurface mining activities will mine through the frac wells that are drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is formed in the cavity created by the extraction of the coal. When the coal is removed, the rock above, which includes as many as 50 thinner coal seams that cannot be mined, collapses into the void. These seams become extensively fractured and release substantial volumes of gas as they collapse. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 26% of our Virginia gas production comes in the form of gob gas.
 
We also drill long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorption of CBM from the coal seam. As of December 31, 2007, we have drilled 15 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. The results from these wells are encouraging and suggest that a more efficient recovery of gas in place is possible ahead of mining operations. The production rates from frac wells have not been adversely impacted by the introduction of nearby horizontal wellbores in the coal seam. In fact, we believe production at offsetting frac wells has actually increased due to the further reductions in pressure within the coal seam caused by the horizontal wells. We intend to increase our use of the horizontal wells drilled within an active mine in our future development plans. In-mine horizontal wells accounted for approximately 1% of Virginia production in 2007, while it is estimated to account for approximately 1.5% of future daily production.
 
 
We have 193,000 net acres of Huron shale potential in Kentucky and Virginia; a portion of this acreage has tight sands potential. Our 2008 exploration program includes projected expenditures for testing the Huron shale.
 
 
Through a joint venture known as Knox Energy, LLC, in which we have a working interest, we control oil and gas rights (including the Chattanooga shale) and CBM rights on approximately 102,000 net leasehold acres in Anderson, Campbell, Morgan, Scott, and Roane Counties, Tennessee. Knox Energy farmed out limited drilling rights on this acreage to a third party through January 31, 2008; we are currently negotiating an extension through December 31, 2012. Under the extension being negotiated, Knox Energy retains the right to participate up to a 50% working interest in wells drilled by the third party. Knox Energy also retains the right to propose and drill horizontal wells in the Chattanooga shale formation, subject to the third party’s right to participate at a 25% working interest. As of December 31, 2007, we have 34.875 net wells that we are operating, while we also participate in another 22.125 net wells operated by a third party. In total, we have an inventory of approximately 2,900 drilling locations on this acreage, none of which are proved undeveloped locations. At December 31, 2007, we had 3.6 Bcfe of proved reserves in this area. Our overall Chattanooga shale acreage position is 132,000 net acres. Our 2008 exploration program includes projected expenditures for testing the Chattanooga shale.
 
We also control other property in east Kentucky and Tennessee that represents approximately 225,000 net CBM acres.
 
Northern Appalachia
 
 
We have the right to extract CBM in this region from approximately 684,000 net CBM acres, which contain most of the recoverable coal reserves owned or controlled by CONSOL Energy in Northern Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We


7


Table of Contents

produce gas primarily from the Pittsburgh #8 coal seam. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh #8 seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to over 7,000 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
 
Due to the significant geological differences between the Pittsburgh #8 seam in Mountaineer and the Pocahontas #3 seam in Virginia, we have found that alternative extraction techniques are more effective than vertical frac wells in this area. Instead of using frac wells, we utilize well designs that rely on the application of vertical-to-horizontal drilling techniques. This well design includes a vertical wellbore that is intersected by a second well that has up to four horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending up to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of coal surface area allowing for the migration of water and CBM from the coal seam. This design creates up to 12,000 feet of total productive wellbore. The wells are spaced in sections up to a square mile. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region associated with CONSOL Energy’s mines.
 
In 2007, we drilled 62 vertical-to-horizontal CBM wells in Mountaineer. We expect to achieve peak production rates of nearly 4 Mcf/d per 100 feet of lateral exposure in the development of the Pittsburgh #8 seam area of this play. As of December 31, 2007, wells that have been de-watered are meeting this expectation.
 
 
We have the right to extract CBM in this region of Pennsylvania from approximately 248,000 net CBM acres. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. In 2007, we drilled 14 wells and connected 10 wells, which are currently producing CBM. Our 2008 program includes expenditures for 100 development wells.
 
 
We have 161,000 net acres of Marcellus shale potential in Ohio, Pennsylvania, West Virginia, and New York. Our 2008 exploration program includes projected expenditures for testing the Marcellus shale.
 
 
We have approximately 61,200 acres with shallow oil potential in Ohio that we are currently assessing.
 
Others
 
 
As of December 31, 2007, we controlled approximately 300,000 net acres of rights to gas in the New Albany shale in Kentucky, Illinois, and Indiana. The New Albany shale is a formation containing gaseous hydrocarbons and our acreage position has thickness of 50-300 feet at an average depth of 2,500-4,000 feet. As of December 31, 2007, we have identified test well locations and we have spudded several exploratory wells. We are using a standard drilling rig to drill up to 4,000 vertical feet. We also have identified the potential for shallow oil and CBM in this area and will continue to evaluate.
 
 
We also control 573,000 net CBM acres, including 92,000 net CBM acres which contain most of the recoverable coal reserves owned or controlled by CONSOL Energy in Illinois.


8


Table of Contents

 
We have the right to extract CBM on 139,000 net acres in the San Juan Basin, 38,000 net acres in the Powder River Basin, 41,000 net acres in eastern Ohio, and 51,000 net acres in central West Virginia. We also have the right to extract Oil and Gas on 43,000 net acres in the San Juan Basin, 9,000 net acres in the Powder River Basin, and 53,000 net acres in various other areas.
 
 
                                 
    Central
    Northern
             
    Appalachia     Appalachia     Other     Total  
 
Estimated Net Proved Reserves (Bcfe)
    1,242.4       87.3       13.8       1,343.5  
Percent Developed
    48.8 %     58.1 %     100 %     50.0 %
Net Producing Wells
    2,650       195       144       2,989  
Net Proved Developed CBM Acres
    134,968       52,760             187,728  
Net Proved Undeveloped CBM Acres
    33,370       35,980             69,350  
Net Unproved CBM Acres(1)
    425,431       934,822       749,902       2,110,155  
                                 
Total Net CBM Acres
    593,769       1,023,562       749,902       2,367,233  
                                 
Net Proved Developed Oil & Gas Acres
    6,104             34,737       40,841  
Net Proved Undeveloped Oil & Gas Acres
                       
Net Unproved Oil & Gas Acres(1)
    314,959       177,255       358,414       850,628  
                                 
Total Net Oil & Gas Acres
    321,063       177,255       393,151       891,469  
                                 
 
(1) Includes areas leased to others or participation interests in third party wells as well as small acreage in other areas.
 
 
During the twelve months ended December 31, 2007, 2006 and 2005, we drilled 370, 272, and 184 net development wells, respectively, all of which were productive. Gob wells and wells drilled by other operators that we participate in are excluded. As of December 31, 2007, we had no dry development wells, and 32 wells are still in process. The following table illustrates the wells referenced above by geographic region:
 
 
                         
    For the Twelve Months Ended December 31,  
    2007     2006     2005  
    Wells     Wells     Wells  
 
Central Appalachia
    294       253       176  
Northern Appalachia
    76       19       8  
                         
Total
    370       272       184  
                         


9


Table of Contents

During the twelve months ended December 31, 2007, 2006 and 2005, we drilled in the aggregate 9, 4, and 15 net exploratory wells, respectively. The following table illustrates the exploratory wells by geographic region:
 
 
                                                                         
    As of December 31,  
    2007     2006     2005  
    Producing     Dry     Still Eval.     Producing     Dry     Still Eval.     Producing     Dry     Still Eval.  
 
Central Appalachia
    3       0       0       2       0       0       2       0       0  
Northern Appalachia
    0       0       0       0       0       2       13       0       0  
Other
    1       0       5       0       0       0       0       0       0  
                                                                         
Total
    4       0       5       2       0       2       15       0       0  
                                                                         
 
 
 
The following table sets forth net sales volume produced for the periods indicated, including our portion of equity affiliates.
 
                         
    For the Twelve Months
    Ended December 31,
    2007   2006   2005
 
Total Produced (Mmcf)
    58,249       56,135       48,390  
 
 
The following table sets forth the average sales price, including hedging transactions, and the average lifting cost, including our portion of equity interests, for all of our gas production for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.
 
                         
    For the Twelve Months
    Ended December 31,
    2007   2006   2005
 
Average Gas Sales Price Including Effects of Financial Settlements (per Mcf)
  $ 7.20     $ 7.04     $ 5.90  
Average Lifting Cost (per Mcf)
  $ 0.68     $ 0.60     $ 0.64  
 
 
Most of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth, at December 31, 2007, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:
 
                 
    Gross     Net(1)  
 
Producing Wells
    3,800       2,989  
Proved Developed Acreage
    230,545       228,569  
Proved Undeveloped Acreage
    71,434       69,350  
Unproven Acreage
    3,505,970       2,960,783  
                 
Total Acreage
    3,807,949       3,258,702  
                 


10


Table of Contents

(1) Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
 
 
CNX Gas enters into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance, we have not failed to deliver quantities required under contract. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 18.4 Bcf of our produced gas sales volumes for the twelve months ended December 31, 2007 at an average price of $8.01 per Mcf. As of December 31, 2007, we expect these transactions will cover approximately 24.5 Bcf of our estimated 2008 production at an average price of $8.30 per Mcf.
 
CNX Gas has purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2007, CNX Gas has secured firm transportation capacity to cover more than its 2008 hedged production.
 
The hedging strategy and information regarding derivative instruments used are outlined in “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Qualitative and Quantitative Disclosures About Market Risk,” and in Note 16 to the Consolidated Financial Statements.
 
 
The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the SEC Rule 4.10(a) of Regulation S-X.
 
                                                 
    Net Reserves (Mmcfe)  
    As of December 31,  
    2007     2006     2005  
    Consolidated
          Consolidated
          Consolidated
       
    Operations     Affiliates     Operations     Affiliates     Operations     Affiliates  
 
Estimated proved developed reserves
    667,726       3,584       609,700       2,200       549,574       2,672  
Estimated proved undeveloped reserves
    672,183             653,593             578,150        
                                                 
Total estimated proved developed and undeveloped reserves
    1,339,909       3,584       1,263,293       2,200       1,127,724       2,672  
                                                 


11


Table of Contents

 
The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:
 
                         
    Discounted Future Net Cash Flows  
    As of December 31,  
    2007     2006     2005  
    (Dollars in thousands)  
 
Future net cash flows (net of tax)
  $ 3,609,195     $ 2,483,887     $ 5,149,938  
Total PV-10 measure of pre tax discounted future net cash flows(1)
  $ 2,287,427     $ 1,499,664     $ 3,051,866  
Total standardized measure of after tax discounted future net cash flows
  $ 1,389,540     $ 934,891     $ 1,870,794  
 
(1) We calculate our PV-10 value in accordance with the following table. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation to the most directly comparable GAAP measure — after-tax discounted future net cash flows.
 
 
                         
    As of December 31,  
    2007     2006     2005  
    (Dollars in thousands)  
 
Future cash inflows
  $ 9,509,665     $ 7,105,265     $ 11,675,551  
Future Production Costs
    (3,004,619 )     (2,568,731 )     (2,852,033 )
Future Development Costs (including abandonments)
    (636,436 )     (552,114 )     (422,315 )
                         
Future net cash flows (pre-tax)
    5,868,610       3,984,420       8,401,203  
10% discount factor
    (3,581,183 )     (2,484,756 )     (5,349,337 )
                         
PV-10 (Non-GAAP measure)
    2,287,427       1,499,664       3,051,866  
                         
Undiscounted Income Taxes
    (2,259,415 )     (1,500,533 )     (3,251,265 )
10% discount factor
    1,361,528       935,760       2,070,193  
                         
Discounted Income Taxes
    (897,887 )     (564,773 )     (1,181,072 )
                         
Standardized GAAP measure
  $ 1,389,540     $ 934,891     $ 1,870,794  
                         
 
 
We operate primarily in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on operating cost and the proximity of gas fields to customers.
 
 
As of December 31, 2007, CNX Gas had 281 employees. None of our employees is represented by a union.


12


Table of Contents

 
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and proxy statements and other documents with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934. All documents that we file with the SEC are available for reading and copying in the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please contact the SEC at 1-800-SEC-0330 for further information regarding the operations of the public reference room. These SEC filings are also available over the Internet at the SEC’s website, www.sec.gov.
 
We make copies of these documents available on our own Internet website, www.cnxgas.com, as soon as reasonably possible after we have furnished such information to the SEC. Information contained on or connected to our website which is not directly incorporated by reference into this Form 10-K should not be considered part of this report or any other filing that we make with the SEC.
 
In addition, charters for the committees of our Board of Directors and our Code of Ethics and Business Conduct, one for directors and the other for employees, can be found on our Internet website under the heading “Corporate Governance.” Stockholders may request copies of these documents by writing to the Investor Relations Department at 5 Penn Center West, Suite 401, Pittsburgh, Pennsylvania 15276-0102. Our Code of Employee Business Conduct and Ethics applies to CNX Gas’ Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer), principal accounting officer or controller and persons performing similar functions. If CNX Gas makes any amendments to the code other than technical, administrative, or other non-substantive amendments, or grants any waivers, including implicit waivers, from a provision of the code applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, CNX Gas will disclose the nature of the amendment or waiver, its effective date and to whom it applies on its website or in a report on Form 8-K filed with the Securities and Exchange Commission.
 
 
The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of wells after gas operations are completed, the discharge or release of materials into the atmosphere and the environment, and the effects of gas well operations on groundwater quality and availability. Additional regulations, including regulations applicable to mine safety, may also be applicable to gas operations producing coalbed methane in relation to active mining. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change operations significantly or incur substantial costs.
 
 
Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines and penalties. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to CNX Gas and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new environmental regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste.


13


Table of Contents

It is not possible to quantify the costs of compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the twelve months ended 2007, 2006 and 2005. Any environmental costs are in addition to well closing costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.
 
The magnitude of the liability and the cost of complying with environmental laws and regulations cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for disposal.
 
CNX Gas is subject to various generally-applicable federal environmental laws, including the following:
 
  •  the Clean Air Act;
 
  •  the Clean Water Act;
 
  •  the Toxic Substances Control Act;
 
  •  the Endangered Species Act;
 
  •  the Resource Conservation and Recovery Act; and
 
  •  the Emergency Planning and Community Right-to-Know Act;
 
as well as state laws of similar scope and substance in each state in which we operate.
 
These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained all required permits under federal and state environmental laws for our current gas operations. Further, we believe that we are in substantial compliance with such permits. However, if violations of permits, failure to obtain permits or other violations of federal or state environmental laws are discovered, we could incur significant liabilities: to correct such violations; to provide additional environmental controls; to obtain required permits; and to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.
 
From time to time, we have been the subject of investigations, administrative proceedings, and litigation, by government agencies and third parties, relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.


14


Table of Contents

 
Various aspects of CNX Gas’ operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
 
Regulations and orders set forth by the Federal Energy Regulatory Commission also impact the business of CNX to a certain degree. Although the Federal Energy Regulatory Commission does not directly regulate CNX Gas’ production activities, the Federal Energy Regulatory Commission has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commission continues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. Additional Federal Energy Regulatory Commission orders were adopted based on this review with the goal of increasing competition for natural gas markets and transportation.
 
The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.
 
CNX Gas owns certain natural gas pipeline facilities that we believe meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction.
 
Additional proposals and proceedings that might affect the gas industry may be pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. CNX Gas cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, CNX Gas does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CNX Gas or its subsidiaries. No material portion of CNX Gas’ business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.
 
 
CNX Gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. CNX Gas’ operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells, and generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of


15


Table of Contents

production. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CNX Gas’ gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CNX Gas does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and CNX Gas is unable to predict the future cost or impact of complying with such regulations.
 
 
The majority of our drilling operations are conducted on properties related to CONSOL Energy’s coal holdings. Our existing rights are often dependent on CONSOL Energy having obtained valid title to its properties.
 
CONSOL Energy’s past practice has been to acquire ownership or leasehold rights to its coal properties prior to conducting its coal mining operations. Given CONSOL Energy’s long history as a coal producer we believe it has a well developed ownership position relating to its coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to its coal holdings, its ownership position relating to these property estates is less developed. As is customary in the coal and gas industry, a summary review of the title to coal, CBM and other gas rights is made on properties at the time of the acquisition of the other rights in the properties. Prior to the commencement of gas drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence our drilling operations on a property until we have cured any material title defects on such property. We completed title work on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas industry.
 
Our natural gas properties are subject to customary royalty and other interests and burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
 
The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to traditional natural gas resources may differ materially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report.
 
 
In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can be sold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under the terms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. As a result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership or leasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam.
 
 
The vast majority of CBM we produce as well as our proved reserves are in Virginia. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM absent an express grant of CBM, natural gases, or minerals in general.


16


Table of Contents

The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. This Court has also found that the owner of the CBM did not have the right to fracture the coal in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.
 
In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of CBM by an operator in those instances where the owner of the CBM has not leased it to the operator or in situations where there are conflicting claims of ownership of the CBM. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.
 
 
In West Virginia, its Supreme Court has held that, in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2007, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia.
 
West Virginia has enacted a law, the Coalbed Methane Well and Units Act (the “West Virginia Act”), regulating the commercial recovery and marketing of CBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s forced pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia coalbed methane review board to obtain authority to produce CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner) but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of CBM from that well.
 
We anticipate in future years to more actively explore for and develop Northern Appalachian CBM in West Virginia. As indicated, we may need or desire to acquire additional rights from other holders of real estate interests, including acquiring rights from other real estate interest holders if the law at that time continues to lack clarity on ownership rights to CBM in West Virginia. As we explore and develop this other acreage where CONSOL Energy has coal rights and has leased/conveyed to us CONSOL Energy’s rights to CBM, we expect in accordance with our existing procedures to have a title examination performed of CONSOL Energy’s rights to CBM. If we believe we need to obtain additional rights from the holders of other real estate interests, we have developed a methodology as part of deciding the feasibility of developing a particular tract to evaluate the ability to locate and negotiate a royalty arrangement with those other holders or use force pooling under the West Virginia Act.
 
 
We have been transferred rights to extract CBM held by CONSOL Energy in other states where it has coal reserves, including the states which comprise the Illinois Basin and certain other western basins. The ownership of CBM in these other states may be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.


17


Table of Contents

 
The following is a description of the meanings of some of the oil and gas industry terms used in this Annual Report.
 
Appalachian Basin.  A mountainous region in the eastern United States, running from northern Alabama to New York, and including parts of Georgia, South Carolina, North Carolina, Tennessee, Kentucky, Pennsylvania, Virginia, and all of West Virginia.
 
Bcf.  Billion cubic feet of natural gas.
 
Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
Btu or British Thermal Unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
CBM.  Coalbed methane.
 
Central Appalachia.  As used in this Annual Report, Central Appalachia includes Virginia, Tennessee, east Kentucky and southern West Virginia.
 
Coal Seam.  A single layer or stratum of coal.
 
Completion.  The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.
 
Development well.  A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.
 
Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Exploitation.  Ordinarily considered to be a form of development within a known reservoir.
 
Exploratory well.  A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
 
Farm-in or farm-out.  An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
 
Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Frac well.  A vertical well drilled in advance of mining and producing from zones artificially fractured or stimulated and which is capable of producing natural gas.
 
Gathering system.  Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.
 
Gob.  The de-stressed zone associated with any full seam extraction of coal that extends above and below the mined out coal seam, and which may be sealed or unsealed.
 
Gob gas.  Gas produced from (a) a well drilled in advance of mining or after mining for the purpose of extracting natural gas from the gob or (b) a frac well that is recompleted for the purpose of extracting natural gas from the gob.


18


Table of Contents

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.
 
Mcf.  Thousand cubic feet of natural gas.
 
Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMBtu.  Million British thermal units.
 
Mmcf.  Million cubic feet of natural gas.
 
Mmcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
Net acres or net wells.  The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
Northern Appalachia.  As used in this Annual Report, Northern Appalachia includes Pennsylvania, northern West Virginia, and southern New York.
 
NYMEX.  The New York Mercantile Exchange.
 
Panel.  A contiguous block of coal that generally comprises one operating unit.
 
Pay zone.  The section of rock, from which gas is expected to be produced in commercial quantities.
 
Pipeline imbalance (imbalance).  We have an operational balancing agreement with Columbia Gas Transmission Corporation (“Columbia”). This agreement is in accordance with the Council of Petroleum Accountants Societies’ definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CNX Gas is responsible for monitoring this imbalance and making adjustments to sales volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser.
 
PV-10 or present value of estimated future net revenues.  An estimate of the present value of the estimated future net revenues from proved gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
 
Proved reserves.  The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
 
Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
 
Reserve life index.  This index is calculated by dividing total proved reserves by the production from the previous year to estimate the number of years of remaining production.


19


Table of Contents

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
Shut in.  Stopping an oil or gas well from producing.
 
Tcfe.  Trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.
 
Vertical-to-horizontal well.  A well in which the drilling from the surface initially proceeds vertically until reaching a particular depth, at which point, the drill bit is turned to proceed at up to 90 degrees from vertical in order to follow a particular stratum or pay zone.
 
Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
 
 
Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive Officers of CNX Gas Corporation” (included herein pursuant to Item 401(b) of Regulation S-K).
 
ITEM 1A.   RISK FACTORS
 
In addition to the trends and uncertainties described in Item I of this Annual Report and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” CNX Gas is subject to the trends and uncertainties set forth below.
 
General Risk Factors
 
 
Our revenue, profitability and cash flow depend upon the prices and demand for natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do.
 
Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
 
  •  the domestic and foreign supply of natural gas;
 
  •  the price of foreign imports;
 
  •  overall domestic and global economic conditions;
 
  •  the consumption pattern of industrial consumers, electricity generators and residential users;
 
  •  weather conditions;
 
  •  technological advances affecting energy consumption;


20


Table of Contents

 
  •  domestic and foreign governmental regulations;
 
  •  proximity and capacity of gas pipelines and other transportation facilities; and
 
  •  the price and availability of alternative fuels.
 
Many of these factors may be beyond our control. Earlier in this decade, natural gas prices were lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including:
 
  •  our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and
 
  •  access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.
 
Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change, or our exploration results deteriorate, accounting rules may require us to write down as a non-cash charge to earnings the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
 
 
Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. We have in the past retained the services of independent petroleum engineers to prepare reports of our proved reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.
 
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:
 
  •  geological conditions;
 
  •  changes in governmental regulations and taxation;
 
  •  assumptions governing future prices;
 
  •  the amount and timing of actual production;
 
  •  future operating costs; and
 
  •  capital costs of drilling new wells.


21


Table of Contents

 
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2007 would decrease from $2,287,427 to $2,239,746. The standardized GAAP measure associated with this decline of $0.10 per Mcf, would be approximately $1,359,939.
 
 
Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2007, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.
 
 
The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for CBM or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:
 
  •  unexpected drilling conditions;
 
  •  title problems;
 
  •  pressure or irregularities in geologic formations;
 
  •  equipment failures or repairs;
 
  •  fires or other accidents;
 
  •  adverse weather conditions;
 
  •  reductions in natural gas prices;
 
  •  pipeline ruptures; and
 
  •  unavailability or high cost of drilling rigs, other field services and equipment.
 
Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.
 
 
In 2008 and beyond we plan to conduct testing and development activities in areas where we have little or no proved reserves, such as certain areas in Pennsylvania and Kentucky. These exploration, drilling and production activities will be subject to many risks, including the risk that CBM or natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for the gas to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling


22


Table of Contents

for CBM, natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.
 
 
We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, which will also increase our unit costs. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could curtail our flows until the gas delivered to their pipeline is in compliance.
 
 
Due to current industry demands, well service providers and related equipment are in short supply. The demand for qualified and experienced field personnel to drill wells and conduct field operations, including geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, inefficient drilling operations, and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.
 
 
The gas industry is intensely competitive and we compete with companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, its operating results and financial position may be adversely affected. For example, one of our competitive strengths is as a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area.
 
In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.


23


Table of Contents

 
From time to time we consider various acquisition opportunities. We could be subject to significant liabilities related to any completed acquisition. Generally, it is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. However, even a detailed review of all properties and records may not reveal existing or potential problems in all of the properties, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities prior to acquisition. We will not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed.
 
In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing on terms acceptable to us or regulatory approvals.
 
Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Future acquisitions could result in our incurring additional debt, contingent liabilities, expenses and diversion of resources, all of which could have a material adverse effect on our financial condition and operating results.
 
 
Coal shale and other strata frequently contain water that must be removed in order for the gas to detach from the coal and flow to the wellbore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability. Further, a substantial amount of our gas needs to be processed in order to make it salable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas from a particular well, or group of wells, may outweigh the economic benefit of selling that gas, and our profitability may decrease due to the reduced production and sale of gas.
 
 
Our business requires disciplined execution at all levels of our organization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requires an experienced and talented management and production team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives and/or the members of our team that have developed substantial expertise in coalbed methane extraction, such as Nicholas DeIuliis, Chief Executive Officer and President, our business could be materially adversely affected. No employment agreements have been or are expected to be executed with these key executives. Furthermore, our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified managerial and production personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.


24


Table of Contents

 
We have entered into several joint venture arrangements with third parties. For example, we are involved with third parties including New River Energy, LLC with respect to Knox Energy (exploration and production) (as described above, we have a working interest in the properties controlled by Knox Energy which are further subject to a farm-out agreement with Atlas America) and Coalfield Pipeline Company (Coalfield Pipeline) (gas pipeline), and Allegheny Energy Supply with respect to Buchanan Generation, LLC (Buchanan Generation) (peaker electrical power generation plant); we are parties to a joint exploration agreement with Kelly Oil & Gas, Inc. (Kelly Oil), Excelsior Exploration Corporation, Ceja Corporation (exploration and production), and a third-party operator. We may also enter into other arrangements like these in the future. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture and the performance of these third parties’ obligations or their ability to meet their obligations under these arrangements are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements may be adversely affected. If our current or future joint venture partners are unable to meet their obligations we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights that may cause disputes among our joint venture parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.
 
 
We and our principal stockholder, CONSOL Energy, are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment, health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, control of surface subsidence from underground mining and work practices related to employee health and safety. Complying with these requirements, including the terms of our and CONSOL Energy’s permits, has had, and will continue to have, a significant effect on our respective costs of operations and competitive position. In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental and health and safety laws. Moreover, given our relationship with CONSOL Energy, its compliance with these laws and regulations could impact our ability to effectively produce gas from our wells.
 
Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.
 
 
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often


25


Table of Contents

required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
 
 
Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired by CONSOL Energy primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “forced pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and these costs may be material. Further, the forced pooling process is time-consuming and may delay our drilling program in the affected areas.
 
In addition, although CONSOL Energy has conveyed to us all of their rights to extract and produce CBM from locations where they possess rights to coal, in some cases CONSOL Energy may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop the CBM with CONSOL Energy’s mining of coal, as provided in the master cooperation and safety agreement. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce CBM from those locations or the feasibility of obtaining those rights.
 
In addition to acquiring these property right assets on an “as is, where is basis”, we have assumed all of the liabilities related to these assets, even if those liabilities were as a result of activities occurring prior to CONSOL Energy’s transfer of those assets to us. Our assumption of these liabilities is subject to the following allocation: we will be responsible for the first $10,000 of aggregate unknown liabilities; CONSOL Energy will be responsible for the next $40,000 of aggregate unknown liabilities; and we will be responsible for any additional unknown liabilities over $50,000. We will also be responsible for any unknown liabilities which were not asserted in writing by August 7, 2010.
 
 
Although we believe that we hold sufficient rights to all of our advanced extraction techniques, other persons could contest our rights and claim ownership of one or more of our advanced techniques for extracting CBM. For example, a third party has asserted that several of our drilling techniques infringed several patents that they hold. A successful challenge to one or more of our advanced extraction techniques could adversely impact our financial performance and results of operation. We might have to pay a royalty which would increase our production costs or cease using that technique which could raise our production costs or decrease our production of CBM. In addition, we could incur substantial costs in defending patent infringement claims, obtaining patent licenses, engaging in interference and opposition proceedings or other challenges to our patent rights or intellectual property rights made by third parties or in bringing such proceedings.


26


Table of Contents

 
In many places where we extract CBM, the coal estate is dominant. In those cases, the coal operator, including, for example, CONSOL Energy and other entities, could exercise its rights to determine when and where certain drilling can take place in order to ensure the safety of the mine or to protect the mineability of the coal.
 
 
The vast majority of our producing properties are geographically concentrated in three counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.
 
 
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. As part of our separation from CONSOL Energy, subject to certain rights and indemnifications, we assumed all of the liabilities related to the gas assets and operations which were transferred to us, including liabilities resulting from operations prior to the effective date of the separation. Arrangements with CONSOL Energy significantly limit our seeking indemnification from CONSOL Energy for unknown liabilities that we have assumed. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.
 
 
Methane, the primary gas which we produce, is a greenhouse gas which is approximately 20 times more potent than carbon dioxide. Most of the coalbed methane we produce would otherwise be vented into the atmosphere in connection with coal mining activities, so our business could be viewed as a significant contributor to the reduction of greenhouse gas emissions and we may get credit for those reductions. We have voluntarily reported those reductions of greenhouse gas emissions to the Environmental Protection Agency for several years. Absent final determination by law, the master cooperation and safety agreement leaves open for negotiation ownership as between us and CONSOL Energy of the greenhouse gas reduction benefits of our production activities both prior to and subsequent to the 2005 separation; we have an oral agreement with CONSOL Energy pursuant to which we and CONSOL Energy each receive 50% of any such benefits.
 
The U.S. Congress is considering climate change legislation that proposes to restrict greenhouse gas emissions. Moreover, several states have already adopted, and other states are considering the adoption of, legislation or regulations to reduce emissions of greenhouse gases. If any Federal or state legislation or regulations that are ultimately adopted do not exempt coalbed methane from their coverage, we could have to curtail production, pay higher taxes or incur costs to purchase allowances that permit us to continue our operations. If any Federal or state legislation or regulations that are ultimately adopted do not give us credits


27


Table of Contents

for capturing methane that would otherwise be vented, thereby reducing greenhouse gas emissions, the value of our historical and future credits would be reduced or eliminated.
 
 
To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of December 31, 2007, we had hedges on approximately 24.5 Bcf of our targeted 2008 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.
 
In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
 
  •  our production is less than expected; or
 
  •  the counterparties to our futures contracts fail to perform the contracts.
 
If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market. This may result in more volatility in our income in future periods.
 
 
At December 31, 2007, we had no borrowings under our revolving credit facility. However, we have significantly increased our planned capital expenditures for 2008 and may incur significant indebtedness in order to fund a portion of these expenditures. We may incur additional indebtedness in the future.
 
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:
 
  •  requiring us to dedicate a portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
 
  •  limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
 
  •  making us vulnerable to increases in interest rates, because our revolving credit facility provides for variable rates of interest;
 
  •  limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
 
  •  reducing our ability to successfully withstand a downturn in our business or the economy generally.
 
Our revolving credit facility contains numerous financial and other restrictive covenants. See Note 8 to the Consolidated Financial Statements for more detail. Our ability to comply with the covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our obligations under those agreements. We may not have sufficient funds to make such payments. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other


28


Table of Contents

financing. We cannot assure that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
 
Risks Relating to Our Relationship with CONSOL Energy
 
Our principal stockholder, CONSOL Energy, is in a position to affect our ongoing operations, corporate transactions and other matters, and some of our directors also serve on its board of directors and/or are employees of CONSOL Energy, creating potential conflicts of interest.
 
Our principal stockholder, CONSOL Energy, owns 81.7% of our outstanding shares of common stock. As a result, CONSOL Energy will be able to determine the outcome of all corporate actions requiring stockholder approval. For example, CONSOL Energy will continue to control decisions with respect to:
 
  •  the election and removal of directors;
 
  •  mergers or other business combinations involving us;
 
  •  future issuances of our common stock or other securities; and
 
  •  amendments to our certificate of incorporation and bylaws.
 
Any exercise by CONSOL Energy of its control rights may be in its own best interest which may not be in the best interest of our other stockholders and our company. CONSOL Energy’s ability to control our company may also make investing in our stock less attractive. These factors in turn may have an adverse effect on the price of our common stock.
 
In addition, some of our directors serve as directors or officers of CONSOL Energy, and/or own CONSOL Energy stock, stock units or options to purchase CONSOL Energy stock, or they may be entitled to participate in the CONSOL Energy compensation plans. CONSOL Energy provides, and may in the future provide additional, cash- and equity-based compensation to employees or others based on CONSOL Energy’s performance. These arrangements and ownership interests or cash- or equity-based awards could create, or appear to create, potential conflicts of interest when directors or executive officers who own CONSOL Energy stock or stock options or who participate in the CONSOL Energy equity plan arrangements are faced with decisions that could have different implications for CONSOL Energy than they do for us. These potential conflicts of interest may not be resolved in our favor.
 
 
The relationship between CONSOL Energy and us may give rise to conflicts of interest with respect to, among other things, transactions and agreements among CONSOL Energy and us, issuances of additional voting securities and the election of directors. When the interests of CONSOL Energy diverge from our interests, CONSOL Energy may exercise its substantial influence and control over us in favor of its own interests over our interests. Our certificate of incorporation and the master cooperation and safety agreement entitle CONSOL Energy to various corporate opportunities which might otherwise have belonged to us and relieve CONSOL Energy and its directors, officers and employees from owing us fiduciary duties with respect to such opportunities.
 
 
We have entered into agreements with CONSOL Energy which govern various transactions between us and our ongoing relationship, including registration rights, tax sharing and indemnification. All of these agreements were entered into while we were a wholly-owned subsidiary of CONSOL Energy, and were negotiated in the overall context of CONSOL Energy creating CNX Gas. As a result, these agreements were not negotiated at arm’s-length. Accordingly, certain rights of CONSOL Energy, particularly the rights relating to the number of demand and piggy-back registration rights that CONSOL Energy will have, the assumption by us of the registration expenses related to the exercise of these rights, our indemnification of CONSOL Energy for certain liabilities under these agreements, our payment of taxes and the retention of tax attributes


29


Table of Contents

may be more favorable to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future which also may not be deemed to be independently negotiated.
 
 
Our business strategy anticipates future acquisitions of natural gas and oil properties and companies. Any acquisition that we undertake would be subject to the limitations and restrictions set forth in our agreements with CONSOL Energy and could be subject to our ability to access capital from outside sources on acceptable terms through the issuance of our common stock or other securities.
 
 
We and CONSOL Energy are obligated to indemnify each other for certain matters as set forth in our agreements with CONSOL Energy. As a result, any claims made against us that are properly attributable to CONSOL Energy (or conversely, claims against CONSOL Energy that are properly attributable to us) in accordance with these arrangements could require us or CONSOL Energy to exercise our respective rights under the master separation agreement and the master cooperation and safety agreement. In addition, we have an agreement with CONSOL Energy that we will refrain from taking certain actions that would result in CONSOL Energy being in default under its debt instruments. Those debt instruments currently contain covenants that would be breached if we borrow from a third party unless we contemporaneously guaranteed indebtedness of CONSOL Energy under those debt instruments. In addition, those debt instruments contain covenants that would be breached by our granting liens on certain assets unless we contemporaneously grant a pari passu lien securing the indebtedness of CONSOL Energy under those debt instruments. In connection with our obtaining an unsecured credit facility with a group of commercial lenders, we guaranteed CONSOL Energy’s $250,000 7.875% notes due March 1, 2012. We are exposed to the risk that, in these circumstances, CONSOL Energy cannot, or will not, make the required payment or in turn that we are required to make a required payment to CONSOL Energy. If this were to occur, our business and financial performance could be adversely affected.
 
Approximately 14% of our gas production is associated with CONSOL Energy’s active mining operations. If CONSOL Energy is required to cease mining activities due to an event causing a coal mine to be idled, that cessation of coal mining could prohibit us from producing gas from that or related sites until the coal mining activities commence again, which could adversely affect our operations and financial results. For example, in 2005 and 2007, CONSOL Energy was forced to idle its Buchanan Mine in southwest Virginia. As a result, we estimate that our total gas production was 4.0 Bcf and 3.7 Bcf less than it otherwise would have been in those years.
 
Further, CONSOL Energy’s coal mining activities at its Buchanan Mine require the removal of water from the mine and the ventilation of the mine. Several lawsuits and permit appeals have been filed that could affect the removal of water from the mine. Separately, a lawsuit has been filed with respect to a ventilation fan that could affect the ventilation of the mine. If operations at CONSOL Energy’s Buchanan Mine are adversely affected as a result of these legal proceedings, our gas production relating to mining activities would be adversely affected.
 
 
On January 29, 2008, CONSOL Energy announced that it intends to make an offer to the stockholders of CNX Gas to acquire all of the outstanding shares of CNX Gas that it does not currently own, in a stock-for-stock transaction that is intended to be tax-free to the stockholders of CNX Gas. Consummation of the offer could result in certain stockholders being required to exchange their shares of CNX Gas stock for the consideration paid by CONSOL Energy in the transaction.


30


Table of Contents

 
Because approximately 27% of our gas production is associated with mining activities, coordination between mining and gas operations can optimize overall energy production. If CONSOL Energy were to divest of a significant interest in us, coordination between us and CONSOL Energy’s mining subsidiaries may be more difficult to accomplish.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 2.   PROPERTIES
 
Our corporate headquarters are located at 5 Penn Center West, Suite 401, Pittsburgh, Pennsylvania 15276-0102. Our other properties are described under “Gas Operations — Areas of Operation” in ITEM 1.
 
ITEM 3.   LEGAL PROCEEDINGS
 
The second through seventh paragraphs of Note 17 — Commitments and Contingent Liabilities in the Notes to the Consolidated Financial Statements included in Part II of this Form 10-K are incorporated herein by reference.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
None.
 
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
The shares of CNX Gas Corporation common stock are listed and traded on the New York Stock Exchange (“NYSE”), under the symbol “CXG”. Our common stock began trading on January 19, 2006, following the effectiveness of our resale registration statement on Form S-1.
 
The quarterly high and low share price for CNX Gas stock was as follows for the 2007 and 2006 quarters ended:
 
                                 
    2007     2006  
    High     Low     High     Low  
 
March 31
  $ 28.69     $ 22.90     $ 26.50     $ 20.13  
June 30
  $ 32.69     $ 27.14     $ 32.99     $ 24.50  
September 30
  $ 32.24     $ 23.47     $ 30.10     $ 21.84  
December 31
  $ 33.20     $ 28.50     $ 28.47     $ 22.12  
 
As of December 31, 2007 there were 9 holders of record of the Company’s common stock; we believe that there are significantly more beneficial holders of our stock.


31


Table of Contents

 
The following performance graph compares the cumulative shareholders’ return on the common stock of CNX Gas Corporation (CXG) to the cumulative return for the same period of the S&P Oil and Gas Exploration and Production index and the S&P MidCap 400 Index. The chart below was structured in a quarterly format rather than yearly because CNX Gas has only been a public company since January 2006.
 
The graph assumes that the value of the investment in CNX Gas common stock and each index was $100 at January 19, 2006 (the date CNX Gas’ shares were listed on the NYSE). The graph also assumes that all dividends, if any, were reinvested and that investments were held through December 31, 2007.
 
COMPARISON OF CUMULATIVE TOTAL RETURN
 
(COMPANY LOGO)
 
                                                                         
    Base Period
    Quarter Ending  
Company/Index
  Jan-19-06     Mar-06     Jun-06     Sep-06     Dec-06     Mar-07     Jun-07     Sep-07     Dec-07  
 
CNX Gas Corporation
    100       115.56       133.33       102.98       113.33       125.91       136.00       127.87       142.00  
S&P MidCap 400 Index
    100       102.89       99.66       98.58       105.47       111.58       118.10       117.08       113.88  
S&P Oil & Gas Exploration & Production
    100       93.20       96.25       92.46       95.84       102.53       115.69       121.28       138.41  
 
The foregoing graph shall not be deemed to be filed as part of the Form 10-K and does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other filing of CNX Gas under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent CNX specifically incorporates the graph by reference.
 
We currently retain our earnings for the development of our business and do not expect to pay any cash dividends. Other than the special dividend of approximately $420,200 we paid to CONSOL Energy with the net proceeds from the private placement of the shares of CNX Gas described below, we have not paid any cash dividends from the date of our inception.
 
See Part III, Item 11, Executive Compensation for information relating to CNX Gas equity compensation plans.
 
 
During the past three years, we have issued and sold unregistered securities in the transactions described below:
 
(1) In July of 2005, we issued 100 shares of common stock to Consolidation Coal Company in exchange for one hundred dollars in connection with the incorporation of CNX Gas. We relied on the


32


Table of Contents

exemption under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), in connection with the offer and sale of those shares.
 
(2) On August 1, 2005, we issued 122,896,567 shares of common stock to our then sole stockholder, Consolidation Coal Company, in exchange for the contribution to us of all of CONSOL Energy Inc.’s (Consolidation Coal Company’s sole stockholder) gas business. We relied on the exemption under Section 4(2) of the Securities Act in connection with the offer and sale of those shares.
 
(3) On August 8, 2005, we completed a private placement of 24,292,754 shares of common stock, 21,778,867 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 1,086,980 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 1,426,907 of which were offered and sold to accredited investors pursuant to Rule 506 under the Securities Act. Friedman, Billings, Ramsey & Co., Inc. (“FBR”) served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering, we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $23,321 was $365,363. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.
 
(4) On August 11, 2005, following the exercise by FBR of an over-allotment option in connection with the above referenced private placement, we completed the sale of 3,643,913 shares of common stock, 822,702 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 51,300 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 2,769,911 of which were offered and sold to accredited investors pursuant to Rule 506 under the Securities Act. FBR served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering, we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $3,498 was $54,804. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.
 
(5) In reliance on Rule 701 and Rule 506 of the Securities Act of 1933, during August 2005, CNX Gas issued options to purchase CNX Gas common stock to our employees and executive officers at an exercise price of $16.00 per share and restricted stock units to our non-employee and non-CONSOL Energy employee directors. We also granted a small number of options to new employees in September 2005 at an exercise price of $20.50 per share, and in November 2005, at an exercise price of $20.75 per share. A total of 358,370 options to purchase CNX Gas common stock were granted to CNX Gas employees, other than our executive officers. Messrs. DeIuliis, Smith, Johnson and Bench received stock options in the aggregate amount of 670,556 shares and Mr. Johnson received 2,969 restricted stock units. Similarly, we granted restricted stock units to each director of CNX Gas that is not an employee of CNX Gas or CONSOL Energy. Mr. Baxter, chairman of the board of directors, was granted 60,000 restricted stock units. Each other such director received 10,000 restricted stock units. The foregoing one-time grants were made in consideration for future service of the employees, executive officers and directors to CNX Gas.


33


Table of Contents

ITEM 6.   SELECTED FINANCIAL DATA
 
The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the twelve months ended December 31, 2007, 2006, 2005, 2004, and 2003 are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2007, 2006, 2005, 2004, and 2003 and the related consolidated statements of income and cash flows for each of the twelve months ended December 31, 2007, 2006, 2005, 2004, and 2003, and the related notes. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included in this Annual Report.
 
CNX GAS CORPORATION AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
 
                                         
    For the Twelve Months Ended December 31,  
STATEMENTS OF INCOME DATA
  2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
RESULTS OF OPERATIONS
                                       
Outside Sales
  $ 404,835     $ 385,056     $ 277,031     $ 214,721     $ 145,884  
Related Party Sales
    11,618       8,490       6,052       22,036       32,572  
Royalty Interest Gas Sales
    46,586       51,054       45,351       41,858       32,442  
Purchased Gas Sales
    7,628       43,973       275,148       112,005        
Other Income
    6,641       25,286       9,859       6,916       4,485  
                                         
TOTAL REVENUE AND OTHER INCOME
    477,308       513,859       613,441       397,536       215,383  
                                         
Lifting Costs
    38,721       33,357       30,399       27,250       22,792  
Gathering and Compression Costs
    61,798       58,102       43,903       40,422       31,997  
Royalty Interest Gas Costs
    40,011       41,998       36,641       32,914       24,200  
Purchased Gas Costs
    7,162       44,843       278,720       113,063        
Other
    79       1,082       2,878       3,009       10,788  
General and Administrative
    54,825       39,168       19,129       15,303       11,995  
Depreciation, Depletion and Amortization
    48,961       37,999       35,039       32,889       33,600  
Interest Expense
    5,606       870       14              
                                         
TOTAL COSTS AND EXPENSES
    257,163       257,419       446,723       264,850       135,372  
                                         
Earnings Before Income Taxes, Minority Interest, and Cumulative Effect of Change in Accounting Principle
    220,145       256,440       166,718       132,686       80,011  
Minority Interest
    494                          
                                         
Earnings Before Income Taxes, and Cumulative Effect of Change in Accounting Principle
    220,639       256,440       166,718       132,686       80,011  
Income Taxes
    84,961       96,573       64,550       51,898       31,202  
                                         
Earnings Before Cumulative Effect of Change in Accounting Principle
    135,678       159,867       102,168       80,788       48,809  
Cumulative Effect of Change in Accounting for Asset Retirement Obligations (Net of Tax Impact of $1,879)
                            2,905  
                                         
NET INCOME
  $ 135,678     $ 159,867     $ 102,168     $ 80,788     $ 51,714  
                                         


34


Table of Contents

                                         
    For the Twelve Months Ended December 31,  
STATEMENTS OF INCOME DATA
  2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
Earnings Per Share Before Cumulative Effect of Change in Accounting Principle
                                       
Basic
  $ 0.90     $ 1.06     $ 0.76     $ 0.66     $ 0.40  
                                         
Diluted
  $ 0.90     $ 1.06     $ 0.76     $ 0.66     $ 0.40  
                                         
Earnings Per Share from Net Income:
                                       
Basic
  $ 0.90     $ 1.06     $ 0.76     $ 0.66     $ 0.42  
                                         
Diluted
  $ 0.90     $ 1.06     $ 0.76     $ 0.66     $ 0.42  
                                         
Weighted Average Number of Common Shares Outstanding:
                                       
Basic
    150,886,433       150,845,518       134,071,334       122,896,667       122,896,667  
                                         
Dilutive
    151,133,520       151,017,456       134,137,219       122,988,359       122,988,359  
                                         
 
                                         
    As of December 31,  
BALANCE SHEETS DATA
  2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
Working Capital (Deficiency) (Unaudited)
  $ 25,303     $ 115,824     $ 3,720     $ (35,030 )   $ (7,971 )
Total Assets
    1,380,703       1,155,001       859,167       718,859       664,635  
Long Term Debt (Including current portion)
    72,768       66,470                    
Total Deferred Credits and Other Liabilities
    227,153       153,977       109,226       205,614       170,520  
Stockholders’ Equity
    1,023,237       880,215       679,472       462,556       464,232  
 
                                         
    For the Twelve Months
 
    Ended December 31,  
CASH FLOW STATEMENTS DATA
  2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
Net Cash Provided by Operating Activities
  $ 272,448     $ 243,569     $ 144,997     $ 175,350     $ 143,133  
Net Cash Used in Investing Activities
    (354,227 )     (156,020 )     (108,287 )     (93,114 )     (90,605 )
Net Cash Provided by (Used in) Financing Activities
    6,654       (449 )     (16,640 )     (82,237 )     (52,526 )
 
                                         
    For the Twelve Months
 
    Ended December 31,  
OTHER OPERATING DATA
  2007     2006     2005     2004     2003  
    (Unaudited)  
 
Net Sales Volumes (Bcf)(1)
    58.25       56.14       48.39       48.56       44.46  
Average Sales Price Including Effects of Financial Settlements ($ per Mcf)(1)(2)
  $ 7.20     $ 7.04     $ 5.90     $ 4.90     $ 4.03  
Total Average Costs ($ Per Mcf)(1)
  $ 3.55     $ 3.02     $ 2.72     $ 2.45     $ 2.43  
Net Estimated Proved Reserves (Bcfe)(1)(3)
    1,343       1,265       1,130       1,045       1,004  
 
                                         
    For the Twelve Months
 
    Ended December 31,  
OTHER FINANCIAL DATA
  2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
Capital Expenditures(4)
  $ 357,199     $ 154,243     $ 110,752     $ 89,753     $ 83,869  
EBIT(5) (Unaudited)
    222,452       253,857       166,314       132,686       80,011  
EBITDA(5) (Unaudited)
    271,413       291,856       201,353       165,575       113,611  

35


Table of Contents

 
(1) For entities that are not wholly owned but in which CNX Gas owns a working interest, includes a percentage of their net production, sales or reserves equal to the CNX Gas percentage equity ownership. Knox Energy is included in the equity earnings data in 2007, 2006, 2005, 2004 and 2003. Sales of gas produced by equity affiliates were 0.32 Bcf for the twelve months ended December 31, 2007, 0.22 Bcf for the twelve months ended December 2006, 0.23 Bcf for the twelve months ended December 31, 2005, 0.20 Bcf for the twelve months ended December 31, 2004, and 0.08 Bcf for the twelve months ended December 31, 2003.
 
(2) Represents average net sales price including the effect of derivative transactions.
 
(3) Represents proved developed and proved undeveloped gas reserves at period end for total operations including equity affiliates, of 3.6 Bcfe.
 
(4) Capital expenditures for 2007 include those related to Knox Energy.
 
(5) EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with accounting principles generally accepted in the United States of America, management believes that they are useful to an investor in evaluating CNX Gas because they are used as measures to evaluate a company’s operating performance before debt expense and cash flow. EBIT and EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as substitute for measures of performance in accordance with accounting principles generally accepted in the United States of America. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties.
 
A reconciliation of EBIT and EBITDA to financial net income is as follows:
 
                                         
    For the Twelve Months
 
    Ended December 31,  
    2007     2006     2005     2004     2003  
    (Dollars in thousands)  
 
Net Income
  $ 135,678     $ 159,867     $ 102,168     $ 80,788     $ 51,714  
Add: Interest Expense
    5,606       870       14              
Less: Interest Income
    3,793       3,453       418              
Less: Cumulative Effect of Changes in Accounting for Asset Retirement Obligations, Net of Income Taxes of $1,879
                            2,905  
Add: Income Tax Expense
    84,961       96,573       64,550       51,898       31,202  
                                         
Earnings Before Net Interest and Taxes (EBIT)
    222,452       253,857       166,314       132,686       80,011  
Add: Depreciation, Depletion and Amortization
    48,961       37,999       35,039       32,889       33,600  
                                         
Earnings Before Net Interest, Taxes and Depreciation, Depletion and Amortization (EBITDA)
  $ 271,413     $ 291,856     $ 201,353     $ 165,575     $ 113,611  
                                         


36


Table of Contents

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis should be read in conjunction with “Selected Consolidated Financial and Other Data” and our consolidated financial statements and related notes appearing elsewhere in this Annual Report. This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. See “PART I — Forward Looking Statements” and PART I-Item 1A “Risk Factors.”
 
 
We are a natural gas exploration, development, production and gathering company, operating primarily in the Appalachian Basin. We are largely a CBM gas producer with industry-leading expertise in this type of gas extraction; however, in 2008, we intend to undertake a more significant exploration program in the shale formations we control.
 
The success of our operations substantially depends upon rights we received from CONSOL Energy as a part of our separation. CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of their ownership or rights to CBM and natural gas and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with their coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will, among other things, provide us certain corporate staff services and coordinate our tax filings.
 
In August 2005, CNX Gas sold 27.9 million shares in a private placement transaction. The aggregate net proceeds of the transaction (approximately $420,200) were used to pay a special dividend to CONSOL Energy. CONSOL Energy currently owns 81.7% of our outstanding common stock.
 
We do not currently have any plans to pay dividends; rather, we intend to invest available cash into the expansion of our business, provided that we can do so at rates of return that exceed our cost of capital.
 
Our goal is to create shareholder value by efficiently increasing production and adding reserves, with a continued emphasis on safety. We believe that by working safely, we can enhance our productivity and continue to be a low cost leader in the industry.
 
 
During 2007, we achieved the following:
 
  •  completed another year with no employee-related lost time accidents. We have accumulated over 2.7 million man hours without a lost time accident;
 
  •  drilled a record 294 wells in our Virginia CBM operations;
 
  •  expanded operations in our Mountaineer CBM play in Northern Appalachia with a record 62 new wells drilled in 2007;
 
  •  drilled 14 wells in Nittany, our CBM play in Central Pennsylvania and the first entirely new step-out opportunity for CNX Gas since its inception in 2005;
 
  •  began exploratory drilling in Cardinal, a New Albany shale play in the Illinois Basin;
 
  •  increased our 2007 production by 3.8% from 2006 to 58 Bcf, despite a roof collapse at CONSOL Energy’s Buchanan Mine;
 
  •  increased our proved reserve base by replacing 234% of our production;
 
  •  generated net income of $135,678;
 
  •  maintained our low cost structure relative to our peer group;


37


Table of Contents

 
  •  continued investing in the infrastructure necessary for continued growth; and
 
  •  acquired additional expertise to begin a significant exploration program.
 
In July 2007 CONSOL Energy idled the Buchanan coal mine after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine. This incident resulted in the deferral of approximately 3.7 Bcf of gob gas in 2007. CONSOL Energy re-entered the mine in January 2008, and we expect to resume normal levels of gob gas production in the first quarter of 2008.
 
 
We intend to transition from a CBM producing company to a natural gas exploration and production company.
 
Our 2008 capital expenditures are projected to be $470,000, including $88,000 in exploratory capital. This capital budget includes significant infrastructure capital that is required for the company to achieve its strategic vision of producing 100 Bcf per year by 2010. CNX Gas will continue to re-invest in its core business as long as it can achieve expected rates of return that exceed its weighted average cost of capital.
 
In 2008, we also expect to drill a total of 500 wells that consist of 300 in Virginia, 100 in Mountaineer, and 100 in Nittany.
 
CNX Gas became a registered offset provider on the Chicago Climate Exchange (CCX) during the fourth quarter 2007. CCX is a 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 exceed their targets have surplus allowances to sell or bank; those who fall short of their 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 December 31, 2007, we are awaiting verification 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 December 31, 2007; however, we expect approval for these projects will be received during the first quarter 2008. Sales of these credits will be reflected in income as they occur.
 
On January 29, 2008, CONSOL Energy announced an intention to commence an exchange offer to acquire the 18.3% of outstanding shares of CNX Gas that CONSOL Energy does not currently own.


38


Table of Contents

 
Twelve Months Ended December 31, 2007 compared with Twelve Months Ended December 31, 2006 (Amounts reported in thousands)
 
Net Income
 
Net income changed primarily due to the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Revenue and Other Income:
                               
Outside Sales
  $ 404,835     $ 385,056     $ 19,779       5.1 %
Related Party Sales
    11,618       8,490       3,128       36.8 %
Royalty Interest Gas Sales
    46,586       51,054       (4,468 )     (8.8 )%
Purchased Gas Sales
    7,628       43,973       (36,345 )     (82.7 )%
Other Income
    6,641       25,286       (18,645 )     (73.7 )%
                                 
Total Revenue and Other Income
    477,308       513,859       (36,551 )     (7.1 )%
                                 
Costs and Expenses:
                               
Lifting Costs
    38,721       33,357       5,364       16.1 %
Gathering and Compression Costs
    61,798       58,102       3,696       6.4 %
Royalty Interest Gas Costs
    40,011       41,998       (1,987 )     (4.7 )%
Purchased Gas Costs
    7,162       44,843       (37,681 )     (84.0 )%
Other
    79       1,082       (1,003 )     (92.7 )%
General and Administrative
    54,825       39,168       15,657       40.0 %
Depreciation, Depletion and Amortization
    48,961       37,999       10,962       28.8 %
Interest Expense
    5,606       870       4,736       544.4 %
                                 
Total Costs and Expenses
    257,163       257,419       (256 )     (0.1 )%
                                 
Earnings Before Income Taxes and Minority Interest
    220,145       256,440       (36,295 )     (14.2 )%
Minority Interest
    494             494       100.0 %
                                 
Earnings Before Income Taxes
    220,639       256,440       (35,801 )     (14.0 )%
Income Taxes
    84,961       96,573       (11,612 )     (12.0 )%
                                 
Net Income
  $ 135,678     $ 159,867     $ (24,189 )     (15.1 )%
                                 
 
Net income for 2007 was lower primarily due to deferred production resulting from the Buchanan mine incident, lower insurance proceeds in the current year compared to 2006 and higher administrative and operating costs. The decreased net income was offset in part by additional sales revenue from new wells being brought on-line in 2007.


39


Table of Contents

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
  $ 404,835     $ 385,056     $ 19,779       5.1 %
Related Party Sales
    11,618       8,490       3,128       36.8 %
Royalty Interest Gas Sales
    46,586       51,054       (4,468 )     (8.8 )%
Purchased Gas Sales
    7,628       43,973       (36,345 )     (82.7 )%
Other Income
    6,641       25,286       (18,645 )     (73.7 )%
                                 
Total Revenue and Other Income
  $ 477,308     $ 513,859     $ (36,551 )     (7.1 )%
                                 
 
The decrease in total revenue and other income was primarily due to the accounting change related to purchased gas sales discussed below, as well as lower business interruption insurance in the current year compared to 2006. This was offset by increases in outside sales and related party sales, which resulted from an increased average sales price in 2007 compared to 2006 and increased production related to additional wells being brought on-line in the current year.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Sales Volumes (Bcf)
    57.9       55.9       2.0       3.6 %
Average Sales Price (per Mcf)
  $ 7.19     $ 7.04     $ 0.15       2.1 %
 
The increase in average sales price is the result of CNX Gas realizing general price increases and higher hedging gains in the current year. CNX Gas periodically enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial hedges represented approximately 18.4 Bcf of our produced gas sales volumes for the twelve months ended December 31, 2007 at an average price of $8.01 per Mcf. In the prior year, these financial hedges represented approximately 17.0 Bcf at an average price of $7.42 per Mcf. Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Also included in 2007 are the non-operated net revenue interest volumes and revenues associated with royalty and working interests. These volumes were not available in 2006, and the associated revenues were included in other income. Partially offsetting these increases was the deferral of production related to the Buchanan Mine issue at CONSOL Energy.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Royalty Interest Gas Sales Volumes (Bcf)
    7.2       7.6       (0.4 )     (5.3 )%
Average Sales Price (per Mcf)
  $ 6.44     $ 6.76     $ (0.32 )     (4.7 )%
 
Included in royalty interest gas sales are the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in average sales price relates primarily to reductions in a provision for royalty settlements. The volatility in the monthly volumes and contractual differences among leases, as well as the mix of average and index prices used in calculating royalties also contributes to the variance.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Purchased Gas Sales Volumes (Bcf)
    1.1       6.1       (5.0 )     (82.0 )%
Average Sales Price (per Mcf)
  $ 7.19     $ 7.20     $ (0. 01 )     (0.1 )%
 
Purchased gas sales volumes in the current year 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


40


Table of Contents

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 expired in 2006, while all activity related to 2007 is reflected in transportation expense on a net basis.
 
Other income consists of the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Royalty Income
  $     $ 10,230     $ (10,230 )     (100.0 )%
Business Interruption Insurance
    1,600       10,165       (8,565 )     (84.3 )%
Third Party Gathering Revenue
    1,077       1,341       (264 )     (19.7 )%
Other Miscellaneous
    171       97       74       76.3 %
Interest Income
    3,793       3,453       340       9.8 %
                                 
Total Other Income
  $ 6,641     $ 25,286     $ (18,645 )     (73.7 )%
                                 
 
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 year, these volumes are included in both sales production and reserves.
 
Insurance proceeds in 2007 related to an advance on the settlement of claims under our business interruption insurance policy for losses we sustained related to a CONSOL Energy mining incident at Buchanan Mine which adversely affected our gob gas production in the current year. Insurance proceeds in 2006 related to a CONSOL Energy mining incident in 2005 which negatively impacted our gas production in that year.
 
Third party gathering revenue was lower in 2007 due to the termination in June of our principal third party gathering agreement along with an actualization related to the final settlement.
 
Other miscellaneous income consists of various items, none of which are material period over period.
 
Interest income increased in 2007 as a result of a higher cash balance throughout a majority of the reporting period. CNX Gas anticipates utilizing the credit facility in 2008 due to our increased capital expenditures program.
 
Costs and Expenses
 
Costs and expenses decreased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Costs and Expenses:
                               
Lifting Costs
  $ 38,721     $ 33,357     $ 5,364       16.1 %
Gathering and Compression Costs
    61,798       58,102       3,696       6.4 %
Royalty Interest Gas Costs
    40,011       41,998       (1,987 )     (4.7 )%
Purchased Gas Costs
    7,162       44,843       (37,681 )     (84.0 )%
Other
    79       1,082       (1,003 )     (92.7 )%
General and Administrative
    54,825       39,168       15,657       40.0 %
Depreciation, Depletion and Amortization
    48,961       37,999       10,962       28.8 %
Interest Expense
    5,606       870       4,736       544.4 %
                                 
Total Costs and Expenses
  $ 257,163     $ 257,419     $ (256 )     (0.1 )%
                                 


41


Table of Contents

Total costs and expenses decreased due to the accounting change related to purchased gas costs, partially offset by increased depreciation and administrative costs.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Sales Volumes (Bcf)
    57.9       55.9       2.0       3.6 %
Average Lifting Costs (per Mcf)
  $ 0.67     $ 0.60     $ 0.07       11.7 %
 
Lifting costs per unit sold increased in the current year due to additional staffing, increased service and maintenance costs due to the additional number of wells on-line, increased water disposal costs, higher road maintenance, and the deferral of low cost gob production related to the CONSOL Energy Buchanan Mine. These unit cost increases were partially offset by a decrease in unit costs due to an adjustment in the well plugging liability, as a result of the increase in the estimated average life of our wells.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Sales Volumes (Bcf)
    57.9       55.9       2.0       3.6 %
Average Gathering and Compression Costs (per Mcf)
  $ 1.07     $ 1.04     $ 0.03       2.9 %
 
The increase in gathering and compression unit costs was attributable to additional treating expenses related to the start up of Mountaineer, compressor rentals related to the increased number of wells in the year, and higher power expenses related to increased megawatt hour rates charged by the power company. These increases were partially offset by lower firm transportation costs related to the in-service of the Jewell Ridge lateral in October 2006. These cost increases were proportionately higher than the increase in volumes, which increased our unit cost.
 
                                 
                Percentage
    2007   2006   Variance   Change
 
Royalty Interest Gas Sales Volumes (Bcf)
    7.2       7.6       (0.4 )     (5.3 )%
Average Cost (per Mcf)
  $ 5.53     $ 5.56     $ (0.03 )     (0.5 )%
 
Included in royalty interest gas costs are the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in volumes and price relates to the volatility and 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 Cost Volumes (Bcf)
    1.1       6.1       (5.0 )     (82.0 )%
Average Purchased Gas Costs (per Mcf)
  $ 6.66     $ 7.34     $ (0.68 )     (9.3 )%
 
Purchased gas cost volumes in the current year 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 costs 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 expired in 2006, while all activity related to 2007 is reflected in transportation expense on a net basis.
 
Other costs and expenses decreased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Exploration
  $ 2,253     $ 2,708     $ (455 )     (16.8 )%
Pipeline Imbalance
          (648 )     648       100.0 %
Equity in Earnings of Affiliates
    (2,174 )     (978 )     (1,196 )     (122.3 )%
                                 
Total Other Costs and Expenses
  $ 79     $ 1,082     $ (1,003 )     (92.7 )%
                                 


42


Table of Contents

Exploration costs decreased primarily as a result of less unsuccessful broker fees in the current year as compared to the prior year. CNX Gas anticipates higher exploration costs in 2008 as the transformation to a full fledged Exploration and Production company is realized. The pipeline imbalance is now included in either outside sales or purchased gas costs. Additionally, equity in earnings of affiliates increased in 2007 compared to 2006, primarily due to increased production of approximately 0.1 Bcf from our Knox Energy joint venture.
 
General and Administrative expenses increased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Employee Wages and Related Costs
  $ 19,255     $ 16,582     $ 2,673       16.1 %
Professional Fees
    15,621       8,879       6,742       75.9 %
Short Term Incentive
    5,659       4,702       957       20.4 %
Stock Based Compensation
    5,491       4,502       989       22.0 %
Facilities
    5,049       2,805       2,244       80.0 %
Other
    3,750       1,698       2,052       120.8 %
                                 
Total
  $ 54,825     $ 39,168     $ 15,657       40.0 %
                                 
 
Employee Wages and Related Costs have increased due to the continued increase in staffing as a result of the on-going growth of the company. CNX Gas has gone from 192 employees on December 31, 2006 to 281 employees on December 31, 2007.
 
Professional Fees have increased primarily related to additional legal fees associated with the CDX and GeoMet litigation. CNX Gas also incurred additional consulting expense related the information management software platform that was implemented in 2006. In the prior year these costs were capitalized as part of the implementation, however these costs are expensed in the current year.
 
Short Term Incentive and Stock Based Compensation costs have increased also as a result of the on-going growth of the company as previously mentioned.
 
The increase in Facilities in the current year relates to the establishment of a new company headquarters, and various other offices associated with the continued growth of the company and our entrance into other regions.
 
The increase in Other costs is due primarily to increases in insurance premiums as well as various other items that are not individually significant.
 
Depreciation, depletion and amortization have increased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2007     2006     Variance     Change  
 
Production
  $ 30,945     $ 24,668     $ 6,277       25.4 %
Gathering
    18,016       13,331       4,685       35.1 %
                                 
Total Depreciation, Depletion and Amortization
  $ 48,961     $ 37,999     $ 10,962       28.8 %
                                 
 
The increase in production related depreciation, depletion and amortization was primarily due to increased production combined with an increase in the units of production rates from period to period. These rates 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 using the straight-line method and increased primarily as a result of realizing a full year of the capital lease treatment of the Jewell Ridge lateral, which went into service on October 28, 2006.
 
Interest expense primarily increased as a result of our capital lease obligation on the Jewell Ridge lateral. CNX Gas expects interest expense to increase in 2008 due to the increase in capital spending as compared to the current year.


43


Table of Contents

 
                                 
                      Percentage
 
    2007     2006     Variance     Change  
 
Earnings Before Income Taxes
  $ 220,639     $ 256,440     $ (35,801 )     (14.0 )%
Tax Expense
  $ 84,961     $ 96,573     $ (11,612 )     (12.0 )%
Effective Income Tax Rate
    38.5 %     37.7 %     0.8 %        
 
CNX Gas’ effective tax rate increased in 2007 primarily due to an increase in state tax rates, discussed further in Note 5 to the Consolidated Financial Statements.
 
Twelve Months Ended December 31, 2006 compared with Twelve Months Ended December 31, 2005
 
(Amounts reported in thousands)
 
Net Income
 
Net income changed primarily due to the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Revenue and Other Income:
                               
Outside Sales
  $ 385,056     $ 277,031     $ 108,025       39.0 %
Related Party Sales
    8,490       6,052       2,438       40.3 %
Royalty Interest Gas Sales
    51,054       45,351       5,703       12.6 %
Purchased Gas Sales
    43,973       275,148       (231,175 )     (84.0 )%
Other Income
    25,286       9,859       15,427       156.5 %
                                 
Total Revenue and Other Income
    513,859       613,441       (99,582 )     (16.2 )%
                                 
Costs and Expenses:
                               
Lifting Costs
    33,357       30,399       2,958       9.7 %
Gathering and Compression Costs
    58,102       43,903       14,199       32.3 %
Royalty Interest Gas Costs
    41,998       36,641       5,357       14.6 %
Purchased Gas Costs
    44,843       278,720       (233,877 )     (83.9 )%
Other
    1,082       2,878       (1,796 )     (62.4 )%
General and Administrative
    39,168       19,129       20,039       104.8 %
Depreciation, Depletion and Amortization
    37,999       35,039       2,960       8.4 %
Interest Expense
    870       14       856       6,114.3 %
                                 
Total Costs and Expenses
    257,419       446,723       (189,304 )     (42.4 )%
                                 
Earnings Before Income Taxes
    256,440       166,718       89,722       53.8 %
Income Taxes
    96,573       64,550       32,023       49.6 %
                                 
Net Income
  $ 159,867     $ 102,168     $ 57,699       56.5 %
                                 
 
Net income for 2006 was improved primarily due to increases in average sales price and production.


44


Table of Contents

Revenue and Other Income
 
Revenue and other income decreased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Revenue and Other Income:
                               
Outside Sales
  $ 385,056     $ 277,031     $ 108,025       39.0 %
Related Party Sales
    8,490       6,052       2,438       40.3 %
Royalty Interest Gas Sales
    51,054       45,351       5,703       12.6 %
Purchased Gas Sales
    43,973       275,148       (231,175 )     (84.0 )%
Other Income
    25,286       9,859       15,427       156.5 %
                                 
Total Revenue and Other Income
  $ 513,859     $ 613,441     $ (99,582 )     (16.2 )%
                                 
 
The decrease in total revenue and other income was primarily due to the accounting change related to purchased gas sales, partially offset by increased outside sales.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Sales Volumes (Bcf)
    55.9       48.2       7.7       16.0 %
Average Sales Price (per Mcf)
  $ 7.04     $ 5.88     $ 1.16       19.7 %
 
The 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 underlying physical transactions. These physical and financial hedges represented approximately 17 Bcf of our produced gas sales volumes for the twelve months ended December 31, 2006 at an average price of $7.42 per Mcf. In the prior year these hedges represented approximately 38.2 Bcf at an average price of $4.77 per Mcf.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Royalty Interest Gas Sales Volumes (Bcf)
    7.6       6.6       1.0       15.2 %
Average Sales Price (per Mcf)
  $ 6.76     $ 6.92     $ (0.16 )     (2.3 )%
 
Included in royalty interest gas sales are the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions, being higher in the prior year than in the current year. Volumes increased as a result of our current year drilling program.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Purchased Gas Sales Volumes (Bcf)
    6.1       28.7       (22.6 )     (78.7 )%
Average Sales Price (per Mcf)
  $ 7.20     $ 9.59     $ (2.39 )     (24.9 )%
 
Included in purchased gas sales revenue are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia Gas Transmission Corporation (TCO) pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 on January 1, 2006, purchased gas sales and volumes have decreased. The net result for transactions that meet the above criteria is reflected in transportation expense in the current year. Additionally, there are small volumes of gas we purchase from third party producers at market prices less our gathering charge, which we then resell.


45


Table of Contents

Other income consists of the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Royalty Income
  $ 10,230     $ 8,158     $ 2,072       25.4 %
Business Interruption Insurance
    10,165             10,165       100.0 %
Interest Income
    3,453       418       3,035       726.1 %
Third Party Gathering Revenue
    1,341       1,110       231       20.8 %
Other Miscellaneous
    97       173       (76 )     (43.9 )%
                                 
Total Other Income
  $ 25,286     $ 9,859     $ 15,427       156.5 %
                                 
 
Royalty income increased in 2006 compared to 2005 due to increased gas prices and additional production on existing contracts. Royalty income received from third parties is calculated as a percentage of the third parties sales price.
 
Insurance proceeds relate to the settlement of claims for losses we sustained from CONSOL Energy mining incidents that adversely affected our gob gas production in 2005.
 
Interest income increased in 2006 as a result of increased earnings and the fact that CNX Gas retained cash collections as a separate stand alone company for the entire year. For most of 2005, CNX Gas was part of CONSOL Energy and only retained cash after separation from CONSOL Energy.
 
Costs and Expenses
 
Costs and expenses decreased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Costs and Expenses:
                               
Lifting Costs
  $ 33,357     $ 30,399     $ 2,958       9.7 %
Gathering and Compression Costs
    58,102       43,903       14,199       32.3 %
Royalty Interest Gas Costs
    41,998       36,641       5,357       14.6 %
Purchased Gas Costs
    44,843       278,720       (233,877 )     (83.9 )%
Other
    1,082       2,878       (1,796 )     (62.4 )%
General and Administrative
    39,168       19,129       20,039       104.8 %
Depreciation, Depletion and Amortization
    37,999       35,039       2,960       8.4 %
Interest Expense
    870       14       856       6,114.3 %
                                 
Total Costs and Expenses
  $ 257,419     $ 446,723     $ (189,304 )     (42.4 )%
                                 
 
The decrease in total costs and expenses was primarily due to the accounting change related to purchased gas costs.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Sales Volumes (Bcf)
    55.9       48.2       7.7       16.0 %
Average Lifting Costs (per Mcf)
  $ 0.60     $ 0.63     $ (0.03 )     (4.8 )%


46


Table of Contents

Lifting costs per unit sold decreased due to increased production from our ongoing drilling program and savings in well service costs, which were partially offset by higher production taxes as a result of higher pricing.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Sales Volumes (Bcf)
    55.9       48.2       7.7       16.0 %
Average Gathering and Compression Costs (per Mcf)
  $ 1.04     $ 0.91     $ 0.13       14.3 %
 
The increase in gathering and compression costs per unit was attributable to an additional $0.07 per Mcf charge for the purchase of firm transportation capacity on the Columbia pipeline acquired to ensure deliverability of our gas. Due to the application of EITF 04-13, the combining of matching buy/sell transactions accounts for an additional $0.06 per Mcf increase in the current year. Although the net costs associated with similar buy/sell transactions were incurred during the prior period, they were not recorded as part of gathering and compression costs. Instead, they were recorded on a gross basis as purchased gas sales and purchased gas costs. Gathering and compression costs have also increased approximately $0.05 per Mcf due to additional power expenses related to both increased megawatt hour rates charged by our power provider and the use of more electric compressors during the current year that were previously powered by gas for most of the prior year. Maintenance and various other related transactions have decreased $0.03 per Mcf as a result of increased production and the compressor conversions. The sales production used to calculate this unit cost does not include volumes from third parties flowing on our lines.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Royalty Interest Gas Sales Volumes (Bcf)
    7.6       6.6       1.0       15.2 %
Average Cost (per Mcf)
  $ 5.56     $ 5.59     $ (0.03 )     (0.5 )%
 
Included in royalty interest gas costs are the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions, being higher in the prior year than in the current year. Volumes increased as a result of additional wells coming online from our on-going drilling program.
 
                                 
                Percentage
    2006   2005   Variance   Change
 
Purchased Gas Cost Volumes (Bcf)
    6.1       28.7       (22.6 )     (78.7 )%
Average Purchased Gas Costs (per Mcf)
  $ 7.34     $ 9.71     $ (2.37 )     (24.4 )%
 
Included in purchased gas costs are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 on January 1, 2006, purchased gas costs and volumes have decreased. The net result for transactions that meet the above criteria is reflected in transportation expense in the current year.
 
Other costs and expenses decreased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Exploration
  $ 2,708     $ 1,830     $ 878       48.0 %
Imbalance
    (648 )     899       (1,547 )     (172.1 )%
Equity in (Earnings) Loss of Affiliates
    (978 )     149       (1,127 )     (756.4 )%
                                 
Total Other Costs and Expenses
  $ 1,082     $ 2,878     $ (1,796 )     (62.4 )%
                                 
 
Exploration costs increased due to our on-going drilling program.


47


Table of Contents

The gas imbalance has shifted from an under-delivered position in 2005 to an over-delivered position in 2006, and therefore resulted in income for 2006 compared to expense in 2005. Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CNX Gas is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. This decrease in imbalance cost was offset by corresponding decreases in gas sales revenue.
 
Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 because Knox Energy had higher earnings in 2006 compared to 2005 primarily due to production increases at the joint venture and additional service revenue. Buchanan Generation incurred losses that were higher in the current year primarily due to the facility being run for less megawatt hours in 2006 compared to 2005.
 
General and administrative costs increased to $39,168 in 2006 from $19,129 in 2005 primarily due to additional costs related to becoming a separate publicly traded company as a result of the separation of CNX Gas from CONSOL Energy. These increased costs include additional staffing and facilities, incentive compensation plans, stock option plans, legal and accounting fees, Sarbanes-Oxley compliance fees, implementation fees for the information management software platform and various other service costs.
 
Depreciation, depletion and amortization have increased due to the following items:
 
                                 
                Dollar
    Percentage
 
    2006     2005     Variance     Change  
 
Production
  $ 24,668     $ 23,531     $ 1,137       4.8 %
Gathering
    13,331       11,508       1,823       15.8 %
                                 
Total Depreciation, Depletion and Amortization
  $ 37,999     $ 35,039     $ 2,960       8.4 %
                                 
 
The increase in production related depreciation, depletion and amortization is due to the net effect of additional volumes in the current year and a slightly lower unit-of-production rate in 2006 compared to 2005. Rates are generally calculated using the net book value of assets on January 1st divided by proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets being placed in service in 2006, including the effect of the Jewell Ridge lateral.
 
Interest expense increased as a result of the imputed interest associated with recording the Jewell Ridge lateral arrangement as a capital lease for financial accounting and reporting purposes.
 
 
                                 
                      Percentage
 
    2006     2005     Variance     Change  
 
Earnings Before Income Taxes
  $ 256,440     $ 166,718     $ 89,722       53.8 %
Tax Expense
  $ 96,573     $ 64,550     $ 32,023       49.6 %
Effective Income Tax Rate
    37.7 %     38.7 %     (1.0 )%        
 
CNX Gas’ effective tax rate decreased in 2006 primarily due to a reduction in state tax rates, discussed further in Note 5 to the Consolidated Financial Statements.
 
 
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.


48


Table of Contents

 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities in the consolidated financial statements and at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Note 1 of the Notes to the Consolidated Annual Financial Statements included in this Annual Report describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.
 
 
CNX Gas enters into financial derivative instruments to manage our exposure to natural gas and oil price volatility. Our derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), as amended by Statement of Financial Accounting Standards No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities-an amendment of FASB Statement No. 133” (SFAS 138) and Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149).
 
We therefore measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CNX Gas currently utilizes only cash flow hedges that are considered highly effective.
 
CNX Gas formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CNX Gas will discontinue hedge accounting prospectively.
 
 
Effective January 1, 2006, CNX Gas adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (SFAS 123R), which requires the measurement and recognition of compensation expense for all share-based payment awards based on estimated fair values. We have selected the Black-Scholes option pricing model to measure the fair value of our stock options. This option pricing model takes into account variables such as the Company’s stock price, as well as assumptions including the projected stock option exercise behaviors.
 
We adopted SFAS 123R using the modified prospective transition method and therefore have not restated results for prior periods. Under this transition method, stock-based compensation expense for the year ended December 31, 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, “Accounting for Stock-Based Compensation‘‘(SFAS 123). Stock-based compensation expense for all stock-based compensation awards granted after January 1, 2006 is based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R.
 
In accordance with SFAS 123R, the value of the portion of the award that is ultimately expected to vest is expensed by CNX Gas on a straight-line basis over the requisite service period of the award, which is


49


Table of Contents

generally the option vesting term. The portion of the award that is expected to vest is determined by employing an estimated forfeiture rate at the time of the grant and revising such estimate in future periods if actual forfeitures differ from those estimates.
 
Prior to the adoption of SFAS 123R, CNX Gas recognized stock-based compensation expense in accordance with Accounting Principles Board Opinion No. 25. “Accounting for Stock Issued to Employees,” (APB 25). In March 2005, the Securities and Exchange Commission (the SEC) issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC’s interpretation of SFAS 123R and the valuation of share-based payments for public companies. CNX Gas has applied the provisions of SAB 107 in its adoption of SFAS 123R. See Note 13 to the Consolidated Financial Statements for a further discussion on stock-based compensation.
 
CNX Gas also implemented a long-term incentive program effective October 11, 2006. This program allows for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the company’s common stock. The total number of units earned, if any, by a participant will be based on the company’s total stockholder return relative to the stockholder return of a pre-determined peer group of companies. The performance period is from October 11, 2006 to December 31, 2009. CNX Gas recognizes compensation costs on a straight-line basis over the requisite service period, based on the fair value of the PSUs. The fair value of the PSUs will be re-valued quarterly using a Monte Carlo lattice model.
 
 
CNX Gas uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field by field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. We use this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of our exploration and production activities.
 
Proved oil and gas reserves are defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3), and (4) as the estimated quantities of oil and natural gas that current geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. These reserve estimates are disclosed in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.”
 
Our estimation of net recoverable reserves is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. A third party consultant is also engaged to prepare an independent reserve estimate for 100% of our reserves. Our estimates of proved natural gas reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. As a result, our estimates of our proved natural gas reserves are inherently imprecise. Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves may vary substantially from our estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.
 
Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. Likewise, because estimates of reserves significantly impact the Company’s depreciation, depletion, and amortization (DD&A) expense, a change in such estimates could have an impact on net income.
 
 
CNX Gas is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel


50


Table of Contents

involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. We do not believe these proceedings will have a material adverse effect on our consolidated financial position. It is possible, however, that future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the effectiveness of our strategies related to these proceedings.
 
 
CNX Gas accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2007, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $189,684. The deferred tax asset components are evaluated periodically to determine if a valuation allowance is necessary. No valuation allowance has been recognized because CNX Gas has determined that it is more likely than not that all of these deferred tax assets will be realized.
 
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 December 31, 2007, CNX Gas does not anticipate a significant change in our uncertain tax positions or unrecognized tax benefits.
 
 
We have significant obligations related to the closure of gas wells upon exhaustion of gas reserves. We are required to dismantle and remove equipment and restore land at the end of our oil and gas production activities. Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.
 
The fair value that is recorded is dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate. Changes in the variables used to calculate the liabilities can have a significant effect on the gas well closing liabilities.
 
The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.
 
 
We intend to satisfy our future working capital requirements and fund our capital expenditures with cash from operations and our $200,000 credit facility. Our 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. Our obligations under our credit agreement are not secured by a lien on our assets.
 
As a result of our status as a majority-owned subsidiary of CONSOL Energy and having entered into a credit agreement with third party commercial lenders, CNX Gas and its subsidiaries are guarantors of CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000,


51


Table of Contents

which require all subsidiaries of CONSOL Energy that incur third party debt to also guarantee the 7.875% notes. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture governing the 7.875% notes requires CNX Gas to ratably secure the notes.
 
We believe that cash generated from operations and borrowings under our credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), and to provide required financial resources. 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 $9,619 at December 31, 2007. The ineffective portion of the changes in the fair value of these contracts was insignificant for the twelve months ended December 31, 2007, 2006 and 2005, respectively.
 
 
                         
    2007     2006     Change  
 
Cash provided by operating activities
  $ 272,448     $ 243,569     $ 28,879  
Cash used in investing activities
  $ (354,227 )   $ (156,020 )   $ (198,207 )
Cash provided by (used in) financing activities
  $ 6,654     $ (449 )   $ 7,103  
 
Our principal source of cash is our operating cash flow. Because our operating cash flow is highly dependent on oil and gas prices, as of December 31, 2007, we entered into hedging agreements covering 24.5 Bcf, 12.7 Bcf, and 1.8 Bcf for 2008, 2009, and 2010, respectively. Capital expenditures of $295,422 and the acquisition of mineral rights of $61,777 in the year ended December 31, 2007 were funded without using our credit facility. Based on anticipated oil and gas futures prices and our current hedge position, the 2008 capital program is expected to be funded with internal cash flow and our credit facility.
 
  •  Cash provided by operating activities increased primarily due to increased production and higher realized prices. These increases are partially offset by increased operating costs and various other working capital requirements.
 
  •  Cash used in investing activities increased primarily due to higher capital expenditures, which is a result of our continuously expanding drilling program. The 2007 year also included a $61,777 acquisition of mineral rights, as detailed further in Note 2 to the Consolidated Financial Statements, as well as capital expenditures of $8,034 related to our variable interest entity.
 
  •  Cash provided by (used in) financing activities increased primarily due to $8,851 of debt proceeds from our variable interest entity, partially offset by capital lease payments of $2,552 related to the Jewell Ridge pipeline.


52


Table of Contents

 
 
The following is a summary of our significant contractual obligations at December 31, 2007 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, at December 31, 2007 to be as follows:
 
                                         
    Within
    1-3
    3-5
    More Than
       
    1 Year     Years     Years     5 Years     Total  
    (Dollars in thousands)  
 
Long Term Debt Obligations
  $ 3,051     $ 5,800     $     $     $ 8,851  
Capital Lease Obligations
    2,768       6,185       7,162       47,802       63,917  
Interest on Capital Lease Obligation
    4,612       8,575       7,598       17,333       38,118  
Operating Lease Obligations
    1,515       2,633       1,838       1,104       7,090  
Gas Firm Transportation Obligations
    7,870       14,379       9,948       17,095       49,292  
Other Long-Term Liabilities(a)
    118       582       936       19,058       20,694  
                                         
Total Contractual Obligations
  $ 19,934     $ 38,154     $ 27,482     $ 102,392     $ 187,962  
                                         
 
 
(a) This item includes asset retirement obligations, pension, postretirement benefits other than pension and legal contingencies, which are reflected on the balance sheet for the potential settlements of the two cases referenced in Note 17 to the Consolidated Financial Statements. Due to the uncertainty surrounding these settlements, it is difficult to predict if and when a payout may take place.
 
(b) 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.
 
As discussed in “Critical Accounting Policies” and in the Notes to our Consolidated Financial Statements included in this Annual Report, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.
 
 
As described above, we and our wholly-owned subsidiaries are party to a credit agreement dated as of October 7, 2005 with a group of commercial lenders. This credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 with the ability to request an increase in the aggregate outstanding principal amount up to $300,000, including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. At December 31, 2007, our borrowing base is reduced by $14,933 related to outstanding letters of credit, leaving $185,067 of unused capacity.
 
Our ability to borrow and obtain letters of credit under the credit agreement is generally limited to a borrowing base. The required number of lenders will determine this borrowing base by calculating a loan value of CNX Gas’ proved reserves and reducing that number by an equity cushion determined by these lenders.
 
 
CNX Gas had stockholders’ equity of $1,023,000 at December 31, 2007 and $880,000 at December 31, 2006. The increase was primarily attributable to net income for the year ended December 31, 2007, hedging gains, the amortization of stock-based compensation awards, and the tax benefit from stock-based compensation. This increase was partially offset by changes to the actuarial long-term liability gains and losses, and the cumulative effect of adopting FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement 109” (FIN 48). See Consolidated Statements of Stockholders’ Equity in the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.


53


Table of Contents

 
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.
 
 
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141®, “Business Combinations” (SFAS 141R), and Statement of Financial Accounting Standards No. 160, “Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS 160). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141 “Business Combinations” while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements become simultaneously effective January 1, 2009. Early adoption is not permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
 
In February 2007, the Financial Accounting Standards Board Issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FAS 115” (SFAS 159). This Statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of FASB Statement No. 157, Fair Value Measurements. We do not expect this guidance to have a significant impact on CNX Gas; however management is currently assessing the impact of adopting SFAS No. 159.
 
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. We do not expect that this guidance will have a significant impact on CNX Gas; however management is currently assessing the impact of adopting SFAS 157.
 
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. SFAS 158 was issued to address concerns that prior standards on employers’ accounting for defined benefit postretirement plans failed to communicate the funded status of those plans in a complete and understandable way and to require an employer to recognize completely in earnings or other comprehensive income the financial impact of certain events affecting the plan’s funded status when those events occurred. This Statement is effective for financial statements issued for fiscal years ending after December 15, 2006. Additionally, SFAS 158 requires an employer to measure the funded status of each of its plans as of the date of its year-end statement of


54


Table of Contents

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 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURE 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 do 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 to the Consolidated Financial Statements.
 
Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2007 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2007 are provided in the following table:
 
                 
    Incremental
    Decrease
    Assuming a
    Hypothetical
    Price Increase
    of:
    10%   25%
    (Dollars in millions)
 
Pre-Tax Income(1)
  $ 25.4     $ 64.1  
 
 
(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 2008 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 December 31, 2007, the fair value of these contracts was a net gain of $5,881 (net of $3,738 deferred tax). We will continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.


55


Table of Contents

 
 
As of February 15, 2008, 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  
 
2008 Fixed Price Volumes Hedged Mcf
    6,097,938       6,097,938       6,164,948       6,164,948       24,525,772  
Weighted Average Hedge Price/Mcf
  $ 8.39     $ 8.24     $ 8.29     $ 8.29     $ 8.30  
2009 Fixed Price Volumes Hedged Mcf
    4,175,258       2,814,433       2,845,361       2,845,361       12,680,413  
Weighted Average Hedge Price/Mcf
  $ 8.82     $ 8.35     $ 8.39     $ 8.52     $ 8.55  
2010 Fixed Price Volumes Hedged Mcf
    1,824,742                         1,824,742  
Weighted Average Hedge Price/Mcf
  $ 8.78                       $ 8.78  
 
CNX Gas is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review.
 
All CNX Gas transactions are denominated in U.S. dollars, and as a result, we do not have material exposure to currency exchange-rate risks.
 
A change in interest rates does not have a material impact on CNX Gas as a result of no borrowings against the credit facility.


56


 


Table of Contents

 
 
To the Board of Directors and Stockholders of CNX Gas Corporation:
 
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of CNX Gas Corporation and its subsidiaries (“CNX Gas”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, CNX Gas maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). CNX Gas’ management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on CNX Gas’ internal control over financial reporting based on our audits which were integrated audits in 2007 and 2006. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
As discussed in Note 1 to the consolidated financial statements, CNX Gas changed the manner in which it accounts for stock based compensation; defined benefit pension, other postretirement benefit plans, and other employee benefits; and purchases and sales of gas with the same counterparty in 2006.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/  PricewaterhouseCoopers LLP
 
Pittsburgh, Pennsylvania
February 15, 2008


58


Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
 
                         
    For the Twelve Months Ended December 31,  
    2007     2006     2005  
    (Dollars in thousands, except per share data)  
 
Revenue and Other Income:
                       
Outside Sales
  $ 404,835     $ 385,056     $ 277,031  
Related Party Sales
    11,618       8,490       6,052  
Royalty Interest Gas Sales
    46,586       51,054       45,351  
Purchased Gas Sales
    7,628       43,973       275,148  
Other Income
    6,641       25,286       9,859  
                         
Total Revenue and Other Income
    477,308       513,859       613,441  
                         
Costs and Expenses:
                       
Lifting Costs
    38,721       33,357       30,399  
Gathering and Compression Costs
    61,798       58,102       43,903  
Royalty Interest Gas Costs
    40,011       41,998       36,641  
Purchased Gas Costs
    7,162       44,843       278,720  
Other
    79       1,082       2,878  
General and Administrative
    54,825       39,168       19,129  
Depreciation, Depletion and Amortization
    48,961       37,999       35,039  
Interest Expense
    5,606       870       14  
                         
Total Costs and Expenses
    257,163       257,419       446,723  
                         
Earnings Before Income Taxes and Minority Interest
    220,145       256,440       166,718  
Minority Interest
    494              
                         
Earnings Before Income Taxes
    220,639       256,440       166,718  
Income Taxes
    84,961       96,573       64,550  
                         
Net Income
  $ 135,678     $ 159,867     $ 102,168  
                         
Earnings per share:
                       
Basic
  $ 0.90     $ 1.06     $ 0.76  
                         
Diluted
  $ 0.90     $ 1.06     $ 0.76  
                         
Weighted Average Number of Common Shares Outstanding:
                       
Basic
    150,886,433       150,845,518       134,071,334  
                         
Dilutive
    151,133,520       151,017,456       134,137,219  
                         
 
The accompanying notes are an integral part of these consolidated financial statements.


59


Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2007     2006  
    (Dollars in thousands)  
 
ASSETS
Current Assets:
               
Cash and Cash Equivalents
  $ 32,048     $ 107,173  
Accounts Receivable:
               
Trade
    38,680       46,062  
Net Related Party
    1,022       2,745  
Other
    1,406       2,291  
Derivatives
    10,711       10,548  
Recoverable Income Taxes
    972        
Other Current Assets
    3,148       3,917  
                 
Total Current Assets
    87,987       172,736  
Property, Plant and Equipment, Net
    1,254,906       918,162  
Other Assets
    9,526       11,820  
Investments in Equity Affiliates
    28,284       52,283  
                 
TOTAL ASSETS
  $ 1,380,703     $ 1,155,001  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
               
Accounts Payable
  $ 30,263     $ 27,872  
Accrued Royalties Payable
    12,896       11,960  
Accrued Severance Taxes
    2,620       2,576  
Accrued Income Taxes
          2,191  
Deferred Taxes
    1,269       3,091  
Current Portion of Long-term Debt
    5,819       2,573  
Other Current Liabilities
    9,817       6,649  
                 
Total Current Liabilities
    62,684       56,912  
Long-Term Debt
    66,949       63,897  
Deferred Credits and Other Liabilities:
               
Deferred Taxes
    188,415       120,008  
Other Liabilities
    30,965       15,977  
Asset Retirement Obligations
    3,981       9,214  
Derivatives
    1,092       6,465  
Postretirement Benefits Other Than Pension
    2,700       2,313  
                 
Total Deferred Credits and Other Liabilities
    227,153       153,977  
Minority Interest
    680        
                 
Total Liabilities and Minority Interest
    357,466       274,786  
                 
Stockholders’ Equity
               
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,915,198 Issued and Outstanding at December 31, 2007 and 150,864,075 Issued and Outstanding at December 31, 2006
    1,509       1,508  
Capital in Excess of Par Value
    785,575       781,960  
Retained Earnings
    229,962       94,337  
Accumulated Other Comprehensive Income
    6,191       2,410  
                 
Total Stockholders’ Equity
    1,023,237       880,215  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 1,380,703     $ 1,155,001  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


60


Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
 
                                                 
                      Accumulated
    Unearned
       
          Capital In
    Retained
    Other
    Compensation
    Total
 
    Common
    Excess of
    Earnings
    Comprehensive
    on Restricted
    Stockholders’
 
    Stock     Par Value     (Deficit)     Income (Loss)     Stock Units     Equity  
                (Dollars in thousands)              
 
Balance at December 31, 2004
  $     $ 215,710     $ 252,469     $ (5,623 )   $     $ 462,556  
Net Income
                102,168                   102,168  
Gas Cash Flow Hedge (Net of $18,542 tax)
                      (29,110 )(a)           (29,110 )
                                                 
Comprehensive Income (Loss)
                102,168       (29,110 )           73,058  
Issuance of Common Stock
    1,508       418,659                         420,167  
Effect of Tax Basis Step-up
          165,042                         165,042  
Issuance of Restricted Stock units under the Equity Incentive Plan (92,969 units)
          1,487                   (1,487 )      
Stock-Based Compensation
                            205       205  
Dividends paid
                (420,167 )                 (420,167 )
Return of Capital to Parent
          (21,389 )                       (21,389 )
                                                 
Balance at December 31, 2005
    1,508       779,509       (65,530 )     (34,733 )     (1,282 )     679,472  
Net Income
                159,867                   159,867  
Gas Cash Flow Hedge (Net of $23,859 tax)
                      36,382 (b)           36,382  
                                                 
Comprehensive Income
                159,867       36,382             196,249  
Initial adjustment upon adoption of FAS 158 (net of $485 tax)
                      761             761  
Elimination of Unearned Compensation on Restricted Stock Units
          (1,282 )                 1,282        
Stock-Based Compensation
          3,733                         3,733  
                                                 
Balance at December 31, 2006
    1,508       781,960       94,337       2,410 (c)           880,215  
Net Income
                135,678                   135,678  
Gas Cash Flow Hedge (Net of $2,145 tax)
                      4,214 (d)           4,214  
FAS 158 OPEB Adjustment (Net of $190 tax)
                      (296 )           (296 )
FAS 158 Pension Adjustment (Net of $88 tax)
                      (137 )           (137 )
                                                 
Comprehensive Income
                135,678       3,781             139,459  
FASB Interpretation No. 48 Adoption
                (53 )                 (53 )
Stock Options Exercised
    1       302                         303  
Tax Benefit from Stock-Based Compensation
          53                         53  
Amortization of Restricted Stock Unit Grants
          653